Performance of Oil-Based Cement Slurry as a Selective Water

Article pubs.acs.org/IECR

Performance of Oil-Based Cement Slurry as a Selective Water-Plugging Agent in High-Temperature and High-Salinity Cave-Fractured Carbonate Reservoirs Cheng-Dong Yuan,†,§ Wan-Fen Pu,†,§ Fa-Yang Jin,*,†,§ Yu-Chuan Zhang,†,§ Hu Jia,†,§ and Tian-hong Zhao‡ †

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, §School of Petroleum Engineering, ‡School of Chemistry and Chemical Engineering, Southwest Petroleum University, Chengdu, Sichuan 610500, People’s Republic of China S Supporting Information *

ABSTRACT: Excessive water production has been one of the most pressing issues facing oilfields worldwide. The low-level success rate caused by complicated well and reservoir conditions drives the development of an effective selective blocking agent that is suited to a simple plugging technique. In this study, we present a novel selective blocking agent that is oil-based cement slurry (OBCS) mainly composed of 0#diesel, crude oil, class G oil well cement, silica fume, a wetting and dispersing agent (sodium alcohol ether sulfate (AES)), and a retarder GH-9 (a copolymer of 2-acrylamido-2-methyl propane sulfonic acid and itaconic acid). The effectiveness of AES and the compatibility of AES and GH-9 when coexisting in the suspension system were investigated by microscopic experiments. The hydrated phases of the OBCS at 130 °C and high salinity (210 000 ppm) formation water were analyzed by X-ray powder diffraction (XRD). Thermogravimetry/differential scanning calorimetry (TG/ DSC) was employed to study the products and content (mainly calcium hydroxide (CH)). The water-plugging performance of the OBCS was studied by carrying out core physical simulation experiments. XRD analysis reveals the presence of CH, calcium silicate hydrate (two types, Ca2SiO4H2O and Ca6Si3O12H2O), ettringite, killalaite, and Xonotlite. Although TG/DSC analysis fails to calculate the content of CH as expected, it gives an indication that oil exists in the set cement. The results of the microscopic experiments show a good effectiveness of AES and compatibility of AES and GH-9. High-quality plugging performances were observed in core physical simulation experiments. The properties tested indicate that the OBCS is a promising prospect as a selective blocking agent for water treatment in high-temperature and high-salinity cave-fractured carbonate reservoirs.

1. INTRODUCTION Management of unproductive water has been a major challenge facing the petroleum industry. An estimated 210 million barrels of water are produced daily with 75 million barrels (11.9 million m3) of oil worldwide.1 The annual cost of disposing of this water is approximately $5−10 billion in the U.S. and approximately $40 billion worldwide.2 Excessive water production can result from either a problem of the well (mechanical failure) or other reasons related to the reservoir, for instance, water channeling from water table to the well through natural fractures, hydraulic/acid fractures or faults, water breakthrough in high-permeability zones, or water coning.2,3 With most fields depleting and new field developments largely adopting horizontal and high-angle well completions, water control is one of the most pressing issues facing operators worldwide.4 The water shut-off technique conducted appropriately is an effective method for treating excessive water production. Various techniques, including mechanical and chemical shutoff, have been developed to curb this menace in the petroleum industry.1 Unfortunately, the success rate remains low with sporadic and often limited success because of many factors that mainly include the following three aspects: (1) The locations of water entries are not clear and the target zones are unknown. Production logging tool (PLT) is one of the most common practices to identify the source of excessive © 2014 American Chemical Society

water production. However, the PLT available in the market still has some limitations due to the effects of well completions, well accessibility, borehole environment, severe corrosion, mechanical obstruction, washouts in case of open hole, issues related to data interpretation, etc. Especially in highly deviated and horizontal wells, the most advanced PLT has very complex tools that measure instantaneous fluid hold up, fluid density, flow velocity, and temperature under the impacts of complex fluid entry mechanisms and flow dynamic of multiphase flow.5 In addition, the cost of PLT is incredible high. The above factors lead to the fact that the target zones are usually unknown in the water treatment process. (2) The characteristics of blocking agents have not satisfied requirements. In recent years, various blocking agents have been developed to control excessive water. These blocking agents mainly include cement type plugging agents, organic silica gel, gel-based volume expansion grain, cross-linked microspheres, polymer gel, and composite blocking agent, etc., Received: Revised: Accepted: Published: 6137

January 3, 2013 March 10, 2014 March 19, 2014 March 19, 2014 dx.doi.org/10.1021/ie4000129 | Ind. Eng. Chem. Res. 2014, 53, 6137−6149

Industrial & Engineering Chemistry Research

Article

Figure 1. Schematic diagram for the formation of OBCS and wettability reversal.

among which polymer gel has been widely researched.6−9 However, the blocking agents used to date still have some drawbacks, for instance, bad salt tolerance and temperature resistance, weak resistance to washing, low strength, and the absence of selective injection and blocking ability (SIBA). Any of them may cause the failure of water shutoff operation. (3) Complex design contributes to construction difficulties, high risks, and high cost. Horizontal well technology, with its rapid development, has been widely used in various oilfields in many countries, which provides a formidable challenge for water treatments.10 As mentioned before, horizontal wells make detecting the location of water entry more difficult. However, even when the locations of water entry are known, water shut-off process design also is more complex because of long horizontal production sections. In some cases, more packers and inflatable bridge plugs are needed, which not only increases the cost but also raises the operation’s risks because of the difficulties of packer or inflatable bridge plugs setting in wells completed in an open hole.

agents, even the popular organically cross-linked polymer gel system (OCP), cannot concurrently have high-temperature (130 °C) and high-salinity (210 000 ppm) tolerance, high strength, and foremost SIBA. When faced with all of these difficulties, it becomes necessary to develop an effective selective blocking agent that is suited to the simple bullhead technique. OBCS has some advantages over conventional blocking agents in terms of bullhead, temperature resistance, salt tolerance, high strength, and especially SIBA. OBCS is a suspension-dispersion system, which is mainly composed of cement, oil, and dispersant. The formation process of OBCS and wettability reversal provide a reasonable explanation regarding why OBCS can achieve the effect of SIBA. The mechanism of OBCS is shown in Figure 1. The key to successful selective blocking is the combination of cement, wetting and dispersing agents, and crude oil. In this system, the hydrophilic groups of the surfactant wet the surface of cement grains and wrap cement grains, while the lipophilic groups of the surfactant interact with oil. In this way, cement grains can be well-dispersed and suspended in oil and do not rapidly descend. In water shutoff projects, the OBCS are injected into both oil zones and water zones to prevent unwanted water. The injected OBCS has a priority to enter water layer because of low resistance of high-permeability water channels. After the OBCS enters water zones, wettability reversal occurs as OBSC contacts with water. The oil wrapping the surface of cement grains is replaced by formation water. Cement grains are exposed in water, and a hydration reaction happens by which set cement is formed. Finally water zones are blocked by set cement and seepage resistance increases. Whereas the OBCS entering the oil zones will be diluted by crude oil because of cement grains being well dispersed and suspended in crude oil, there is no wettability reversal because of the lack of water or little water existing in oil zones. Therefore, a hydration reaction hardly occurs, and oil zones will not be blocked. Cement grains in oil zones will settle as the efficacy of wetting and dispersing agents is lost at high temperature. Fortunately, the settled cement grains will be discharged when wells are opened for production again after being shut in for about seven days. The longer the production period, the smaller the quantity of particle retention. Consequently, oil zones will not be badly harmed, and oil production will increase and water cut will decrease.

Take Tahe oilfield (Tarim Basin, China) as an example; this oilfield is an Ordovician cave-fractured carbonate reservoir with a strong bottom water, formation temperature 130 °C (approx.), and high salinity (≥200 000 ppm), which requires water shutoff agents having a strong salt tolerance and temperature resistance. However, the polymer gels mostly used are not stable under high temperature and high salinity.11 To address this issue, Yadav et al.11 investigated the properties of a polymer gel up to 120 °C and 40 000 ppm. The results demonstrated that the increased salinity led to gel syneresis. Yang et al12 studied a salt-resisting gel system under the salinity of 28 029.54 ppm. There is still a gap compared with 130 °C and 210 000 ppm salinity. Enough strength is also required to block large caves and fractures under the strong bottom water. Long horizontal wells with open hole completion make detecting water entry locations more difficult and the design more complicated, which raises the operation’s risks and cost. In this case, bullhead13 is a simple and suitable method for water shutoff. However, bullhead is susceptible to causing blockages in the oil zone or both the oil and water zone if blocking agents have no good SIBA. Actually, current blocking 6138

dx.doi.org/10.1021/ie4000129 | Ind. Eng. Chem. Res. 2014, 53, 6137−6149


Article

However, we need to find appropriate additives to satisfy the requirements of water shutoff operations in reservoir conditions like Tahe oilfield. Surfactants should maintain a high stability of OBCS in an oil environment and remain convenient for wettability reversal in a water environment under high temperature and salinity. Retarders should be added to delay thickening time for implementation safety. A number of chemicals are employed to delay the thickening time. Recent work has concentrated on a series of organic phosphonic acids, in particular nitrilo-tris(methylene)phosphonic acid, N[CH2PO-(OH)2]3 (H6ntmp).14 Tartaric acid, modified lignosulfonate, and AMPS copolymer were also investigated.15 In addition, other additives for enhancing the setting properties, such as fly ash, were studied.16,17 AMPS copolymer generally has a high temperature tolerance.18 Therefore, GH-9 (the copolymer of AMPS and itaconic acid) was chosen for delaying thickening time in this research. In this study, we obtained a novel OBCS that can meet the application requirements by screening and evaluating stability, displacement efficiency, and other routine properties in the study of the cement slurry. However, the process of screening and the routine properties tests will not be illustrated in detail and only the results will be presented. In this paper, the main focus is the present work, including (1) the microscopic experiments conducted to further illustrate the effectiveness and the compatibility between the AES and GH-9, (2) examination of the hydration and some hydration products of the OBCS by X-ray diffraction and TG/DSC tests, and (3) evaluation of the dynamic performances of the OBCS after flowing the artificial fractures at high temperature (≥130 °C) by performing core physical simulation experiments.

(≥200 000 ppm) were obtained from Tahe oilfield (Tarim Basin, China), Sinopec Northwest Company, China. 2.2. OBCS and Set Cement Preparation. The dosage of all materials used is shown in Table 1. The dosage was determined Table 1. Dosage of All Materials for Preparing the OBCSa material

dosage (g)

class G oil well cement (solid) silica fume (solid) 0#diesel (liquid) crude oil (liquid) AES (liquid) GH-9 (liquid)

240 60 150 150 7.5 10.5

a

Oil/cement ratio is 1:1. The mass ratio of cement and silica fume is 4:1. The mass ratio of diesel oil and crude oil is 1:1. The proportions of wetting and dispersing agent and the retarder are 2.5% and 3.5%, respectively. The proportions are based on the dry weight of all the solid powder used, including cement and silica fume.

from a large number of experiments designed for screening and optimizing by evaluating oil separation rate, displacement efficiency, and fluidity. The whole process of screening and optimizing is not the purpose of this paper and will not be illustrated in detail here. The preparation process of OBCS and set cements together with the test processes of stability, displacement efficiency, and flowability are presented in the Supporting Information. The set cements formed are shown in Figure 2. 2.3. Microscopic Experiments. Some microscopic experiments were conducted by using a microscope camera system (SZ40-CTV, Olympus, Japan) to further illustrate that the AES used can effectively make cement grains dispersed in oil to form a suspension system, and that AES and GH-9 have a good compatibility when they coexist in the suspension system. A droplet of the prepared slurry was put on the glass slide to observe the flow characteristics by a computer connected to the microscope camera system. Two types of experiments were carried out; one allowed the droplet to flow freely, and the other forced the droplet to flow by adding a coverslip on top of the droplet. 2.4. X-ray Diffraction Test and TG/DSC Test. X-ray powder diffraction (XRD) tests were carried out to analyze the hydrated phases and compare the differences between the set cement obtained from the OBCS and that of the conventional class G oil well cement slurry. The set cement sample prepared was crushed and powdered. The powder obtained was washed with acetone and filtered to remove existing oil in the set cement. This job was continued until the filtered fluid was clear. Then the powder was dried in an oven thermostat at 110 °C for 24 h. XRD patterns were recorded on an XPERT-PRO diffractometer (PANalytical, Netherlands) equipped with an X’Celerator detector and Cu Kα radiation, operating at 40 kV and 40 mA at 25 °C. The diffraction data was collected in the scanning angle (2θ) range

2. EXPERIMENTAL SECTION 2.1. Preparation of Materials. Samples of cement were class G oil well cement and were obtained from Si Chuan Jia Hua Enterprise Co., LTD, China. The class G oil well cement is mainly composed of dicalcium silicate (Ca2SiO4, C2S), tricalcium silicate (Ca3SiO5, C3S), tricalcium aluminate (Ca3Al2O6, C3A), and tetracalcium aluminoferrite (Ca4AlnFe(2−n)O7, C4AF). The specific minerals and content of the class G oil well cement used in the research mainly include 6−14% C4AF, 48−56% C3S, 1−3% C3A, and 28−36% C2S. The retarder, GH-9, was provided by Wei Hui Shi Chemical LTD, China. GH-9 is a copolymer of AMPS and itaconic acid. Silica fume (1000 mesh; silicon content is greater than 95%) was purchased from Chengdu Huiye Silicon Ash Material Co., LTD, China. AES was purchased from Nan Tong Hai shi Hua Gong Zhu Ji CO., LTD, China as a 70 wt % aqueous solution and used without further purification. 0#diesel was provided by one of the filling stations of China National Petroleum Corporation (CNPC). Crude oil (12 mPa·s, 0.856 g/cm3, at 50 °C and 1 atm) and formation water with high salinity

Figure 2. Sample of set cement taken from OWC-9390B curing for 4 days at 130 °C and 20 MPa. 6139



Article

Figure 3. Schematic diagram of single-core physical simulation experimental equipment. A, pump; B, six-way valve; C, injected water; D, water shutoff agent; E, crude oil; F, core holder for fractured core; IPS, Input pressure sensor; OPS, output pressure sensor; APS, annular pressure sensor; MD, metering device; PAN, pump for annular pressure. The devices inside the dotted line were placed in an oven thermostat.

Figure 4. Schematic diagram of double-parallel-core physical simulation equipment. F1, core holder for low-permeability fractured core; F2:, core holder for high-permeability fractured core. Other labels are the same as those used in Figure 3. The devices inside the dotted line were placed in an oven thermostat.

splitting.19 One empirical equation20 was first proposed to calculate the fracture width. However, calculations verified these equations were not suitable to the fractured cores obtained by the method of equal splitting. Therefore, we directly obtained the fracture width by measuring. The results would not be affected as the fracture permeability does really matter for evaluating shutoff performances. This is in fact consistent with reservoir conditions. For Ordovician cavefractured carbonate reservoir of Tahe oilfield, fractures and secondary solution cavities are the main storage spaces and the flow channel of fluid, and the matrix does not have the ability of storage and seepage. The fractured core preparation procedure is presented in the Supporting Information. The petrophysical properties of synthetic core samples are shown in Table 2. (2). Single-Core Flow Experiment for Water-Blocking Rate and Damage Rate. The water-blocking rate is defined for the channel producing unwanted water and is represented by η

of 10−80°, using a step size of 0.017° and a count time of 12 s at each step. X’Pert Highscore Plus software was used for data processing. NETZSCH STA 449F3 (NETZSCH, Ltd., German) was employed for thermal analysis. The crucible with a type of DSC/TG pan Al2O3 was employed for the normal TG/DSC tests at atmospheric pressure, and the temperature range was 40 to 1000 °C with the heating rate of 10 °C/min. Sample weight of the set cement was 10.092 mg in the test. 2.5. Core Physical Simulation Experiment. Dynamic core physical simulation experiments can effectively simulate the plugging performances of the system and provide a reliable and scientific experimental basis for water shutoff projects in the field. Single-core (for assessing water-blocking rate and damage rate) and double-parallel-core flow experiment (for assessing SIBA) were conducted. Figures 3 and 4 show the single-core and double-parallel-core schematic diagrams of the experimental apparatus. (1). Fractured Core Preparation. Natural carbonate cores split equally were used in the experiments. Figure 5 shows the schematic of fractured cores obtained by the method of equal

η= 6140

Kb − Ka × 100% Kb dx.doi.org/10.1021/ie4000129 | Ind. Eng. Chem. Res. 2014, 53, 6137−6149


Article

Figure 5. Schematic of fractured cores obtained by the method of equal splitting. Panels (c) and (d) are pictures of the synthetic core taken from different angles.

water-blocking rate and damage rate evaluation are presented in the Supporting Information. (3). Double-Parallel-Core Flow Experiment for SIBA. The SIBA is the relative ability of OBCS to enter and block large and small fractures when injected into target formations. It can be quantitatively described by the cumulate liquid productions before and after the OBCS injection. The large and small fractures here are used to simulate the main channel producing unwanted water and the channel-less production of water (higher oil saturation) in reservoirs, respectively. The evaluation index of the SIBA mainly includes three aspects: (1) the most water is produced from large fractures in water displacement process before OBCS is injected, (2) the injected OBCS mainly enters into the large fractures, and (3) little water is produced from large fractures after OBCS is injected. One could say that the OBCS has an exellent SIBA if all three goals are achieved. The experimental procedure is presented in the Supporting Information.

Table 2. Petrophycical Properties of Synthetic Core Samples Used in These Experiments core code

D (cm)

L (cm)

Wf (cm)

Kt (mD)

FV (ml)

1 2 3 4 5 6 7 8 9

2.470 2.430 2.510 2.442 2.400 2.460 2.386 2.520 2.636

7.071 7.135 7.136 7.138 7.120 7.269 7.068 7.246 7.098

0.288 0.236 0.169 0.214 0.198 0.305 0.227 0.256 0.362

10 473.67 4 801.70 1 020.35 3 557.20 1 207.63 12 369.80 5 205.83 6 362.09 11 360.65

2.34 1.95 0.88 1.76 0.83 2.45 1.82 1.85 2.86

where Kb and Ka are the core water permeability before and after blocking, respectively. The larger the water-blocking rate, the better the performance of water-blocking agent. The damage rate has a definition and expression that are the same as those of the water-blocking rate. However, it is defined for the channel producing oil. It is also one of key parameters for evaluating plugging effects of blocking agents. As for the damage rate, the smaller the value, the better the performance of the water-blocking agent. The experimental procedures of

3. RESULTS AND DISCUSSION 3.1. Flowability, Stability (Oil Separation Rate), and Displacement Efficiency Tests. A high flowability, that is the radical of more than 30 cm, was achieved, which is enough for pumping in the project in terms of the OBCS. Oil separation

Figure 6. Results of stability test using single-surfactant and compound surfactants. 6141



Article

Figure 7. Images of the slurry without AES and GH-9 that were captured from the video without a coverslip. Panels (a)−(f) are images of different times: (a) is the initial image and (b)−(f) are images captured in sequence. The arrow represents the direction of flow.

challenge to the existing technical level and increases costs greatly. Therefore, balancing all the factors is challenging and requires a comprehensive evaluation. 3.2. Microscopic Experiments. The main focus of this section is the microscopic experiments conducted to further illustrate the effectiveness and the compatibility between AES and GH-9. Figures 7 and 8 show images of the slurry without AES and GH-9 and that of the slurry with AES and no GH-9, respectively, at different times. We can clearly see the difference from the two pictures. The slurry did not hardly flow as a unit when AES was not added (Figure 7). Cement grains remained where they were placed, and only a little oil moved slowly and stopped in a short time (20 s, approximately where Figure 7e was captured). This was a result of cement grains which were not well-suspended in the oil. However, in Figure 8, the slurry flowed as a unit, and cement grains were not separated from the oil. The flow front moved forward steadily and trimly. This suggests a suspension system was well-formed and cement grains were evenly dispersed in the oil. This is further indication that AES exhibits an impressive property of wetting and dispersing. Images of the slurry without AES and GH-9 that were captured from the video with a coverslip added are shown in Figure 9. We know through the analysis of Figure 7 that cement grains cannot be effectively dispersed in the oil as no AES was added. The result was as expected that the slurry still did not flow; even the oil remained in place after the coverslip was added (Figure 9). Figure 10 depicts the images of the slurry with AES but no GH-9 under a coverslip at different times. The white bubbles surrounded by different colored circles originally existed when the coverslip was put on. These can be treated as some exact reference points to facilitate observation. The movement of the slurry as a unit happened again as shown in Figure 10. Compared with Figure 8, the flow velocity is higher with the effect of outside force. It is evident that cement grains

rate is one of the criteria for an optimum process. Figure 6 shows one of the results in optimum process for 1 day. Other results will not be discussed here. From left to right in Figure 6, the oil separation rates are 2%, 1.5%, 4.67%, 5.23%, 6.97%, 8.15%, 11.79%, and 13.67%. The first one from the left is the system used in this paper, and the oil separation rate is 2%, which is a desirable result. We should note that crude oil was totally replaced with 0#diesel to make observation easier in the process of evaluation because the black crude oil is difficult to distinguish in the scales. This will not significantly influence the results because the stability will be better with crude oil because of crude oil’s high viscosity, which can increase the stability of the system. In fact, the oil separation rate was nearly unchanged with further settling for another 2 days, and the slurry could still flow freely as shown in the left part of Figure 6. Also, the result of the displacement efficiency test demonstrates a high displacement efficiency of 70% was achieved, which means more oil in the system will be discharged when the well is opened again for production after water treatment. It will reduce costs significantly. Although good flowability and stability along with a higher displacement efficiency were achieved, it is not easy to make all the properties (including other conventional performances of cement slurry such as thickening time and strength) satisfy the construction in the field. The reason is that each property of OBCS has a different demand for the type of additives, the dosage of additives, and the dosage of other materials used in OBCS. In addition, some economic factors need to be considered. These factors include the fact that a higher cement content in OBCS can help to get much more set cement in the target formation but leads to a bad flowability. In addition, the increased dosage of AES is favorable for improving the flowability but partly contributes to a bad stability. Both high-temperature and high-salinity require larger dosage and better temperature tolerance and salinity tolerance in terms of the additives, but this brings a huge 6142



Article

Figure 8. The images of the slurry with AES and no GH-9 that were captured from the video without coverslip.

Figure 9. Images of the slurry without AES and GH-9 that were captured from the video with a coverslip added.

phenomenon was also observed in the flowability test by using the simple device mentioned in the Supporting Information in the process of screening and evaluating. This is considered to be the influence of GH-9 (AMPS copolymer) on the viscosity of the fluid.16 With the addition of GH-9, the increased viscosity led to a reduction of flowability. Generally, most copolymers can increase the viscosity of a fluid. There have been a number of copolymers used to reduce mobility ratio between displacing fluid and oil for EOR.18,21−23 However, the effect of the GH-9 on

evenly dispersed in the oil under the AES treatment. This result is consistent with the observation obtained from Figure 8, which demonstrates AES can be used to form a stable suspension system as a high-quality wetting and dispersing agent. Figure 11 shows images of the slurry with AES and GH-9 in different times under a coverslip. We can notice that, from Figure 11, the status of the slurry was obviously changed as GH-9 was added. It did not look like as fine and smooth as the images shown in Figure 10. In addition, the flowability lowered slightly. This 6143



Article

Figure 10. Images of the slurry with AES and no GH-9 that were captured from the video with a coverslip added.

Figure 11. Images of the slurry with AES and GH-9 that were captured from the video with a coverslip added.

the flowability was not very significant. The flowability is still in the acceptable range from the project perspective. All present properties of OBCS reflect that AES and GH-9 can coexist in the OBCS system. 3.3. X-ray Diffraction Study. XRD analysis (Figure 12) shows the phases in the set cement sample aging for 4 days prepared as described in the Experimental Section. The analysis revealed the presence CH, C3S, calcium silicate hydrate (two

types, Ca2 SiO4H2O and Ca6Si3O12H2O), ettringite, killalaite, and Xonotlite. The results, by and large, accord with the results of Zhang et al.24 In their study, the hydration products of the conventional cement slurry aging at 110−160 °C in the presence of silica mainly included calcium silicate hydrate (C2SH), CH, ettringite, tobermorite, Xonotlite, etc. There is hardly any C−S−H gel discovered. Instead, we found C6S3H, Xonotlite, and more C2SH. This is because the C−S−H gel 6144



Article

Figure 12. XRD patterns of the set cement aging for 4 days at 130 °C and 20 MPa (In the study of Zhang et al,22 the hydration products of the conventional cement slurry aging at110−160 °C in the presence of silica mainly included calcium silicate hydrate (C2SH), CH, ettringite, tobermorite, Xonotlite, etc.)

formed at first will ultimately be converted into C2SH when the temperature is higher than 110 °C. C2SH could continue to be converted into tobermorite, etc., and further into Xonotlite, etc. as temperature increases in the presence of silica or as other conditions change.24 Peak intensity and amount basically demonstrate ettringite exists as a minor phase, which is consistent with the low C3A content due to ettringite being formed from C3A. This indicates that the retarder GH-9 did little to influence the final hydration of C3A. XRD analysis data also revealed there is a significant amount of C3S residual, which is partly against the inhabitation mechanism of GH-9 proposed by Su et al.25 GH-9 is a copolymer of the AMPS and itaconic acid and contains hydrophilic sulfonic groups and dicarboxylic acid groups. These groups interact with C3A and C3S by adoption, chelation, dispersion, and wetting. The interactions lead to the formation of a diffused double layer that can disperse cement grains. Simultaneously, solvation membranes are formed under the interaction of groups and calcium ions on the surface of cement grains. These solvation membranes are preferably absorbed on the surface of C3A in the early stage of hydration, which inhibits the formation and growth of a crystal nucleus and delays the hydration of C3A. GH-9 exhibits a weak adsorption to C3S. This delaying mechanism partly causes a thickening time of more than 400 min to be achieved in this system and accordingly guarantees a better strength development in the later stages. However, a lot of C3S residual based on XRD data seems to be partly inconsistent with the mechanism. If the residual C3S was not caused by GH-9, the greatest possibility is that crude oil, high salinity, or the combined action of the two factors inhibits the hydration. In addition, the formation water contains various minerals and metal ions (calcium ion, magnesium ion, iron ion, etc.), which make the situation more complicated. The hydration mechanism under the crude oil and formation water is beyond the scope of the present work and needs to be studied further in the future. 3.4. TG/DSC Tests of Set Cement. Figure 13 shows the TG/DSC profiles of sample 2 in air environment. The profiles are really different from that of the common set cement presented by Wang et al.26 In their research, there are obviously two endothermic valleys (100−200 °C and 400−500 °C) on the DSC curve. The first endothermic valley (100−200 °C) was

caused by the dehydration of the initially formed C−S−H and ettringite. The second one is a small, deep valley, from 400 to 500 °C, which is due to the decomposition of CH, and a large amount of heat was absorbed. There is another weak valley in the 650−700 °C range, which represents the decomposition of calcium carbonate. However, Figure 13 depicts a completely different trend. We observed two obvious exothermic peaks, the first is at 345 °C and the second is at 623 °C. To explain the phenomenon of exothermic peaks, we recall that the set cement probably contained crude oil, despite going through the process of washing the set cement with acetone and filtering until the filtered fluid was clear. We know that the set cement was formed in an oil environment because the oil cannot be replaced completely by water in the course of the hydration reaction of cement. Consequently, the crude oil could exist in the set cement in some form. Oxidation between oil and air occurred and released heat when the sample was tested in the air environment. To verify this, a TG/DTA test for crude oil used in the OBCS system was conducted in air environment. Figure 14 shows the heat flow and mass loss curves for Tahe crude oil in atmosphere environment. We tried to explain the heat release of the set cement by combining the two pictures. The first exothermic peaks in Figures 13 and 14 are at 345 and 349 °C, respectively. The positions of the two first peaks are very close, and the heat flows both increased rapidly before achieving the maximum. The high value and the rapid increase of heat flow cannot be achieved by any substance existing in the set cement, which in part indicates that the set cement indeed contained crude oil. The two obvious exothermic peaks in Figure 13 are due to the oil’s reaction with oxygen.The first steep peak was caused by the liquid oil as well as the vapor phase of oil formed in the evaporation process reacting with oxygen and quickly releasing heat. The same exothermic process occurred before 400 °C in Figure 14 and is called low-temperature reaction (LTO) in air injection projects.27−30 However, we can clearly see that there is a significant difference in the two profiles in Figures 13 and 14 after the first exothermic peak. Figure 14 shows a low heat flow phase between 420 and 470 °C followed by another exothermic peak at 544 °C, which are called “fuel deposition” phase and hightemperature oxidation (HTO) in terms of reaction between oil 6145



Article

Figure 13. TG/DSC profiles for set cement (curing for 4 days) in air environment. In the heat flow unit label, “mg” refers to the initial mass of the sample.

Figure 14. Heat flow and mass loss curves for crude oil from Tahe oilfield in atmosphere environment. In the heat flow unit label, “mg” refers to the initial mass of oil.

and oxygen, respectively.27,31−33 In contrast, the profile for the set cement shown in Figure 13 displays different behavior. Only a low heat flow phase appeared between 423 and 530 °C, and there is no exothermic peak. There are two key factors that contributed to the existence of only a low heat flow phase. First is the “fuel deposition” phase, as shown in Figure 14, in which actually only a little heat was released. Second is the decomposition of CH (420−530 °C), needed to absorb much heat lost the water. The heat absorbed can act to at least partially counteract the heat released by HTO. Thus, the combination of the two factors led to only low heat flow without any exothermic peak from 420 to 530 °C, which is exactly consistent with the deep endothermic valley (approximately 400−500 °C) in the DSC curve for common set cement.24 Generally, there should be a weak endothermic valley (600−800 °C)

caused by the decomposition of CaCO3 for common set cement. However, Figure 13 depicts an exothermic peak at 643 °C. This is expected as partial carbonization of the sample of set cement. Simultaneously, the exothermic reaction between oil and oxygen may also conduce the exothermic peak in the range of 643−740 °C, where the other “trapped” oil was liberated from the structure of the set cement as the decomposition of CaCO3 with increasing temperature. However, the “trapped pattern” of the oil in the set cement remains unknown. 3.5. Core Physical Simulation Experiment. (1). SingleCore Flow Experiment for Water-Blocking Rate and Damage Rate. The degree of blocking was evaluated through the data obtained. The results of two group experiments for waterblocking rate are shown in Table 3. The water permeability was decreased significantly, from Kb = 4801.70 mD to Ka = 67.22 mD, 6146



Article

serious harm to the target formations or influence the normal production of oil wells. (2). Double-Parallel-Core Flow Experiments for SIBA. Two couples of cores, core codes 9 and 3 and core codes 6 and 5, which have a permeability contrast value of 11.13 and 10.24, respectively, were chosen for two experiments. The cores with a permeability contrast were chosen to better simulate high- and low-permeability fractures in formations. The results are shown in Table 5. It is clearly seen from both the experiments that the most water (86.30% and 90.80%) was produced from the highpermeability fractures in the water displacement process before OBCS was injected. Simultaneously, there is a similar trend that the slurry of 92.30% and 87.20% entered into the large fractures and only 7.70% and 12.80% entered into the low-permeability fractures in the two experiments. However, the results obtained after blocking were exactly contrary to the results before the slurry was injected. Little injected water (7.30% and 10.40%) was produced from the high-permeability fractures, and most water (92.70% and 89.60%) was produced from the lowpermeability fractures, which is as expected. These results provide indication that the OBCS has selective injection and blocking ability. Thus, the OBCS has a priority to enter into and block the high-permeability fractures of the target formation in water treatment. The degree of blocking for lowpermeability fractures will be lower. In fact, high-permeability fractures usually produce a lot of unwanted water, whereas lowpermeability fractures tend to produce more crude oil after longterm development in cave-fractured or fractured carbonate reservoirs. Consequently, the OBCS will be more suitable to water treatment projects and will improve the effect of water shut off in these reservoirs.

Table 3. Results for Water-Blocking Rate of the Slurry to the Core water permeability (mD) core code

Wf (cm)

Kb

Ka

water-blocking rate, η (%)

2 4

0.236 0.214

4801.70 3557.20

67.22 0

98.60 100.00

in the first group experiment (core code 2). A high waterblocking rate of 98.6% was achieved, which demonstrates that OBCS provides an effective blocking to the fracture. However, in the second group experiment (core code 4), no liquid was displaced out even when injection pressure was above 30 MPa in the injection process in which formation water was reversely injected into the core and the single-phase liquid (formation water) water permeability was tested. This indicates the fractured core was likely blocked very well and the OBCS has a considerably strong blocking ability. The fractures were almost full of set cement with high strength which restricts liquid flow. Therefore, we considered the permeability was equal to zero under the condition of 30 MPa, and the waterblocking rate is 100.00%. In fact, the producing pressure drop is hardly higher than 30 MPa in actual production. Both experiments show OBCS has a strong blocking ability. Table 4 shows the results of the two experiments’ damage rates. The damage rates in the two experiments were lower than Table 4. Results for Damage Rate of the Slurry to the Core water permeability (mD) core code

Wf (cm)

Kb

Ka

damage rate, η (%)

7 8

0.227 0.256

5205.83 6362.09

4328.65 5132.30

16.85 19.33

4. CONCLUSION The performances of the OBCS, mainly including flowability, stability, displacement efficiency, and plugging performances, were tested in this study. The test results demonstrate that the OBCS is a promising selective blocking agent for water shutoff projects in high-temperature and high-salinity cave-fractured or fractured carbonate reservoirs. (1) A high displacement efficiency of 70% was achieved, which implies more oil in the system will be discharged after the water treatment project is finished and normal well production is recovered. An oil separation rate of 2% shows a high stability. A flowability of more than 30 cm was achieved, which is enough for pumping in water treatment projects in terms of cave-fractured carbonate reservoirs. (2) AES could effectively disperse cement grains in the oil and guarantees that wettability reversal could occur

20.00% when crude oil (10PV) was reversely injected, which is an acceptable damage in water treatment projects.34 More slurry injected would be discharged with more crude oil being reversely injected. This would further decrease the damage rate. Still, there is one point that needs to be emphasized regarding the crude oil of ten pore volume. The slurry passed through the whole core in the simulation experiments. However, the OBCS will enter only a part of the fractures in reservoirs. The volume filled with the slurry is minimal compared with the volume of the entire reservoir. Thus, only a small amout of crude oil of recoverable reserves (not 10PV crude oil in the experiments) is required to discharge the slurry injected in water treatment project. The damage rate will be decreased to a lower level, perhaps several percent. In summary, the OBCS will not cause

Table 5. Effects of the Blocking of Double-Parallel-Core Experimenta water permeability (mD) core code

permeability contrast (%)

Wf (cm)

PV (ml)

9 3 6 5

11.13

0.362 0.169 0.305 0.198

3.74

10.24

3.28

relative liquid production (%)

Kb

Ka

entry amount of the slurry (%)

before blocking

after blocking

blocking rate, η (%)

11360.65 1020.35 12369.80 1207.63

105.60 863.22 160.81 1045.47

92.30 7.70 87.20 12.80

86.30 13.70 90.80 9.20

7.30 92.70 10.40 89.60

99.07 15.40 98.70 13.43

a

The PV refers to the total volume of the two cores. The total water injection volume designed was 10PV to reduce errors, and the injection volume of the slurry was still the total volume of the two cores in the experiments. The entry amount of the slurry is the volume percent of the liquid produced to the total injection volume of the slurry. 6147



Article

smoothly at 130 °C and in formation water (salinity is 210 000 ppm). AES and GH-9 generally exhibit a good compatibility in the suspension system. GH-9, by hydrophilic sulfonic groups and dicarboxylic acid groups, could prolong the thickening time of OBCS to more than 400 min at 130 °C and formation water. The presence of oil and formation water is considered to be favorable factor for delaying the thickening time. Nevertheless, the retarding mechanism in the presence of oil and formation water needs further study. (3) The hydrated phases of OBCS under the conditions of formation water and 130 °C curing for 4 days mainly includes CH, calcium silicate hydrate (two types, Ca2 SiO4H2O and Ca6Si3O12H2O), ettringite, killalaite, and Xonotlite. This demonstrates that the hydration of OBCS could proceed normally. TG/DSC analysis reveals oil was “trapped” in the set cement in some form. (4) Core physical simulation experiments demonstrate that the OBCS has a high-quality SIBA. Therefore, the OBCS could primarily enter and effectively block water layers with high-permeability fractures, which made the relative production of liquid drop dramatically. Simultaneously, the relative production of liquid was increased in lowpermeability fractures. A high water-blocking rate of more than 98.00% and a relative low damage rate of less than 20.00% were obtained. This indicates the OBCS provided excellent blocking for large fractures, which mainly produce water, and had a low damage for small fractures, which mainly produce oil. The OBCS combines the properties of temperature tolerance, salinity tolerance, high strength, and foremost selective plugging, which expands the application range of blocking agents, and is suitable for the bullhead technique in complex reservoirs.

■

supporters. A special acknowledgement is made to the members of the EOR Group directed by Wan-Fen Pu (Southwest Petroleum University, China).

■

Abbreviations

OBCS = oil-based cement slurry AES = sodium alcohol ether sulfate AMPS = 2-Acrylamido-2-methyl propane sulfonic acid GH-9 = a copolymer of 2-acrylamido-2-methyl propane sulfonic acid and itaconic acid CH = calcium hydroxide SIBA = selective injection and blocking agent PLT = production logging tool Parameters

η1 = displacement efficiency m = the volume of oil separated, ml m0 = the original volume of oil, ml D = the outside diameter of the core, cm L = length of core, cm FV = fracture volume, ml PV = pore volume, ml Wf = fracture aperture, cm Kt = the effective permeability of whole fractured core (both fracture and core matrix), mD Ka = the core water permeability before blocking, mD Kb = the core water permeability after blocking, mD

Units

■

1 ppm = 1 mg/L = 1 × 10−6 1 mD = 1 ×10−3 D = 1 × 10−3 μm2

REFERENCES

(1) Joseph, A.; Ajienka J. A. A review of water shutoff treatment strategies in oil fields. Presented at the 34th Annual SPE International Conference and Exhibition, Tinapa-Calabar, Nigeria, July 31−August 7, 2010; Paper SPE 136969. (2) Seright, R. S.; Lane, R. H.; Sydansk, R. D. A strategy for attacking excess water production. SPE Prod. Facil. 2003, 18 (3), 158−169. (3) Shahab, U.; Dolan, J.; Chona, R.; Gazi, N.; Ken, M.; Al-Rubaiyea, J.; Anwar, A. S. Lessons learned from the first openhole horizontal well water shutoff job using two new polymer systemsA case history from Wafra Ratawi Field, Kuwait. Presented at the SPE 13th Middle East Oil Show & Conference, Bahrain, April 5−8, 2003; Paper SPE 81447. (4) Nicholas, K. An engineering approach to predicting posttreatment well performance using selective chemical water shut-off techniques: An RPM example. Presented at the SPE Annual Technical Conference and Exhibition, Denver, CO, October 5−8, 2003; Paper SPE 84513. (5) Al Hasani, M.; Al Khayari, S.; Al Maamari, R.; Al-Wadhahi, M. Diagnosis of excessive water production in horizontal wells using WOR plots. Presented at the International Petroleum Technology Conference, Kuala Lumpur, Malaysia, December 3−5, 2008; Paper SPE 11958. (6) Moradi-Araghi, A. A review of thermally stable gels for fluid diversion in petroleum production. J. Pet. Sci. Eng. 2000, 26 (1), 1−10. (7) Vasquez, J.; Eoff, L. Laboratory development and successful field application of a conformance polymer system for low-, medium-, and high-temperature applications. Presented at the SPE Latin American & Caribbean Petroleum Engineering Conference, Lima, Peru, December 1−3, 2010; Paper SPE 139308. (8) Jia, H.; Pu, W. F.; Zhao, J. Z.; Jin, F. Y. Research on the gelation performance of low toxic PEI cross-linking PHPAM gel systems as water shutoff agents in low temperature reservoirs. Ind. Eng. Chem. Res. 2010, 49 (20), 9618−9624.

ASSOCIATED CONTENT

S Supporting Information *

Details regarding OBCS and set cement preparation; stability (oil separation rate), displacement efficiency, and flowability tests; fractured core preparation; experimental procedures of water-blocking rate; experimental procedures of damage rate; and double-parallel-core flow experiment for SIBA. This information is available free of charge via the Internet at http://pubs.acs.org/.

■

NOMENCLATURE

AUTHOR INFORMATION

Corresponding Author

*Xindu Avenue No. 8, 610500, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, People’s Republic of China. Tel.: +86-2813618028704. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS The authors thank Sinopec Northwest Company (China) for permission to publish this paper. This research is financially supported by Key State Science and Technology Project of Large Gas Fields and Coalbed Methane, China (2011ZX05049-0404HZ), as well as the special fund of China’s central government for the development of local colleges and universities, a project of national first-level discipline in Oil and Gas Engineering. The authors express their sincere appreciation for the two financial 6148



Article

(9) Jia, H.; Pu, W. F.; Zhao, J. Z.; Liao, R. Experimental investigation of the novel phenol-formaldehyde cross-linking HPAM gel system: Based on the secondary cross-linking method of organic cross-linkers and its gelation performance study after flowing through porous media. Energy Fuels 2011, 25 (2), 727−736. (10) Permadi, P.; Lee, R. L.; Kartoatmodjo, R. S. T. Behavior of water cresting under horizontal wells. Presented at the SPE Annual Technical Conference & Exhibition, Dallas, TX, October 22−25, 1995; Paper SPE 30743. (11) Yadav, U. S.; Mahto, V. Investigating the effect of several parameters on the gelation behavior of partially hydrolyzed Polyacrylamide−Hexamine−Hydroquinone gels. Ind. Eng. Chem. Res. 2013, 52 (28), 9532−9537. (12) Yang, G.; Zhang, J.; Xue, X. S.; Cui, Y. X.; Zhao, W. S. Development and evaluation of salt-resisting polymer gel profile control agent. Adv. Mater. Res. 2013, 781, 426−430. (13) Wassmuth, F. R.; Green, K.; Hodgins, L. Water shutoff in gas wells: Proper gel placement is the key to success. SPE Prod. Facil. 2004, 19 (4), 217−227. (14) Bishop, M.; Bott, S. G.; Barron, A. R. A new mechanism for cement hydration inhibition: Solid-state chemistry of calcium nitrilotris (methylene) triphosphonate. Chem. Mater. 2003, 15 (16), 3074−3088. (15) Jupe, A. C.; Wilkinson, A. P.; Luke, K.; Funkhouser, G. P. Class H oil well cement hydration at elevated temperatures in the presence of retarding agents: An in situ high-energy X-ray diffraction study. Ind. Eng. Chem. Res. 2005, 44 (15), 5579−5584. (16) Guo, T.; Malone, R. F.; Rusch, K. A. Stabilized phosphogypsum:class C fly ash:portland type II cement composites for potential marine application. Environ. Sci. Technol. 2001, 35 (19), 3967−3973. (17) Lupu, C.; Jackson, K. L.; Bard, S.; Barron, A. R. Water, acid, and calcium carbonate pretreatment of fly ash: The effect on setting of cement-fly ash mixtures. Ind. Eng. Chem. Res. 2007, 46 (24), 8018− 8025. (18) Sabhapondit, A.; Borthakur, A.; Haque, I. Water soluble acrylamidomethyl propane sulfonate (AMPS) copolymer as an enhanced oil recovery chemical. Energy Fuels 2003, 17 (3), 683−688. (19) Zhao, J. Z.; Jia, H.; Pu, W. F.; Liao, R. Influences of fracture aperture on the water-shutoff performance of polyethyleneimine crosslinking partially hydrolyzed polyacrylamide gels in hydraulic fractured reservoirs. Energy Fuels 2011, 25 (6), 2616−2624. (20) Salimi, S.; Alikarami, R. Mechanism of fluid invasion in naturally fractured reservoirs: Experimental study. Presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, LA, Feb 15−17, 2006; Paper SPE 98292. (21) El-Gamal, I. M.; Al-Sabbagh, A. M. Polymeric additives for improving the flow properties of waxy distillate fuels and crudes. Fuel 1996, 75 (6), 743−750. (22) Pedersen, K. S.; Rønningsen, H. P. Influence of wax inhibitors on wax appearance temperature, pour point, and viscosity of waxy crude oils. Energy Fuels 2003, 17 (2), 321−328. (23) Castro, L. V.; Vazquez, F. Copolymers as flow improvers for Mexican crude oils. Energy Fuels 2008, 22 (6), 4006−4011. (24) Zhang, J. F. Hydration, Hardening and Properties of Class G Oil well Cement. Ph.D. Thesis, Zhejiang University, Hangzhou, P.R. China, July 2001 (in Chinese). (25) Su, R. J.; Li, Q. Z. Study and application of high temperature retarder GH-9 for cement slurry. Drilling Fluid & Completion Fuild 2005, 22, 89−92 (in Chinese). (26) Wang, X. Drying shrinkage of hardened cement paste and its relationship to the microstructure. Chongqing University, Chongqing, P.R. China, May 2011 (in Chinese). (27) Jia, H.; Zhao, J. Z.; Pu, W. F.; Zhao, J.; Kuang, X. Y. Thermal study on light crude oil for application of high-pressure air injection (HPAI) process by TG/DTG and DTA tests. Energy Fuels 2012, 26 (3), 1575−1584. (28) Sarma, H.; Yazawa, N.; Moore, R.; Metha, S.; Okazawa, N.; Ferguson, H.; Ursenbach, M. Screening of three light-oil reservoirs for

application of air injection process by accelerating rate calorimetric and TG/PDSC tests. J. Can. Pet. Technol. 2002, 41 (3), 50−60. (29) Li, J.; Mehta, S.; Moore, R.; Zalewski, E.; Ursenbach, M.; Fraassen, K. Investigation of the oxidation behaviour of pure hydrocarbon components and crude oils utilizing PDSC thermal technique. J. Can. Pet. Technol. 2006, 45 (1), 48−53. (30) Kikuchi, I.; Teramoto, T.; Onishi, T. Improved recovery of light oil by air injection. J. Jpn. Assoc. Pet. Technol. 2006, 71 (3), 293−304 (in Japanese). (31) Ren, S. R.; Greaves, M.; Rathbone, R. R. Oxidation kinetics of North Sea light crude oils at reservoir temperature. Chem. Eng. Res. Des. 1999, 77 (5), 385−394. (32) Lukyaa, A. B. A.; Hughes, R.; Millington, A.; Price, D. Evaluation of a North Sea oil for recovery by in situ combustion using high pressure differential scanning calorimetry: Oil and natural gas production. Chem. Eng. Res. Des. 1994, 72 (2), 163−168. (33) Kisler, J. P.; Shallcross, D. C. An improved model for the oxidation processes of light crude oil. Chem. Eng. Res. Des. 1997, 75 (4), 392−400. (34) Wan, J. G.; Fan, Z. Z.; Wang, B. K.; Liu, Q. W. Study and application of a selective plugging agent for oilfields. Adv. Fine Petrochem. 2006, 7 (2), 16−18 (in Chinese).

6149


Performance of Oil-Based Cement Slurry as a Selective Water

Recommend Documents