Reducing Gas Flaring in Oil Production from Shales - Energy & Fuels

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Reducing Gas Flaring in Oil Production from Shales Richard Roehner, Palash Panja, and Milind D. Deo Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01126 • Publication Date (Web): 29 Jul 2016 Downloaded from http://pubs.acs.org on August 4, 2016

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Reducing Gas Flaring in Oil Production from Shales Richard Roehner, Palash Panja and Milind Deo† Department of Chemical Engineering, University of Utah, 50 S. Central Campus Dr., Salt Lake City, UT 84112, USA † Corresponding Author, Tel: +1 (801)581-7629, FAX: +1 (801)585-9291 E-mail address: [email protected] Abstract It is estimated that about a third of the total gas produced from the prolific Bakken Formation – amounting to about 330 million standard cubic feet/day is either vented or flared. The gas flared in the Eagle Ford formation in Texas is also of the order of 300 MMSCF/day. The main target in these plays is liquid (oil and condensate) and the associated gas is flared or vented. Any liquids production from shale will ultimately involve surface production facilities for stabilization, treatment, and transport of produced fluids. The design and operation of the surface production facilities affects the amount and quality of the liquid produced and significantly affects the amount of gas vented. In this paper, we show that by using a two-stage design improves liquid quality while reducing venting rates by up to 70%. The two-stage operation will require additional infrastructure and cost upfront, but will yield considerable technical and environmental benefits, and move tight oil production to a more sustainable operation. Impact of operational change in surface facility and well head on the sub-surface flow is also investigated in this study by simulating a conventional condensate process flowsheet with Eagle Ford fluid. Major pressure drops occur in the vertical section of well and in the well head choke valve where change in flow regime is observed. Up to 10% liquid fall-out inside the reservoir causes loss of production and creates a condensate bank near well bore hindering the gas flow. Introduction Flaring of large amounts of natural gas in Williston Basin in North Dakota and in Eagle Ford in Texas are well known. The production from the Bakken formation has increased spectacularly in the last 10 years. The growth is shown in Figure 1. The oil produced from the Bakken is light and has a significant amount of produced gas. Because of the lack of pipeline and adequate compression infrastructure, approximately a third of that gas is flared.

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Figure 1: Oil production in the Bakken over the last 10 years. Numbers are from the North Dakota Oil and Gas Division. The amount of gas produced from the Bakken has also increased commensurate with the oil production. Over 400 billion cubic feet of gas was produced in 2014 (Figure 2). Of this, about 112 BCF was flared according to numbers available from the North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division. The percentage of gas flared has declined from a high of 40% in 2012 to about 28% in 2014 and to about 20% in 2015. The total amount flared in 2015 was still close to 100 BCF. This amounts to over 350 MMSCF of natural gas flared every day in 2014 from the Bakken formation. Eagle Ford gas production in 2014 was about 1.5 BCF/day and about 25% of that was flared. The flares continue to be the visible environmental consequence of shale development. The pictures of flares in the nighttime from space which make Bakken and Eagle Ford appear as bright as nearby large cities (Figure 3) are often-used visual evidence of all that is wrong with the otherwise highly technically and economically successful enterprise.


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Figure 2: The total annual gas production from the Bakken, and the amount flared is shown.

Figure 3: The Bakken and the Eagle Ford flares at night as seen from space. These nonurban areas look as bright as some of the larger metropolitan areas. Source – NASA.

Werner et al. (2014) discuss the environmental public health dimensions of shale and tight gas development. They conclude that even though data gaps persist, there is evidence that the environmental aspects of development including venting and flaring contribute to public health risks associated with shale development. Benefits of not flaring and using the gas have also been discussed in the literature. Hoffman et al. (2014) showed that reinjection of the gas would lead to improved recovery, while Wallace and Ehlig-Economides (2015) discuss using the gas to generate power. Both hydrocarbon and flue-gas injections were discussed by Ling et al. (2014). 3 ACS Paragon Plus Environment

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The reasons for this large amount of gas flaring are multifaceted. With the rapid pace of unconventional development, and rapidly evolving understanding associated with low permeability reservoir production, there has been little time for utilizing the best practices unconventional surface facilities. Some literature has been coming out relating to design of shale gas surface facilities, since initial shale gas development pointed the way for potential production of shale liquids. Several key themes can be identified relating to the complexity associated with production of liquids (and gas) from shale in these recent papers, which were best summarized by Guarnone, et al. (Guarnone et al., 2012). Individual production per well is lower for unconventional wells than for conventional wells. Production from shale plays usually involves higher numbers of wells per wellpad. Conventional surface developments might be typified by 6 to 8 wells per pad, while the number of wells per pad in unconventional plays may be increasing to 12 to 20 on a typical basis. Larger well pads are needed to accommodate more wells, and to co-locate gas-oil separators, typically one per well. These well pads are generally being clustered together, feeding gathering networks that need to be designed to allow continual re-work of existing wells in addition to drilling of new wells. Stock tanks are typically initially provided, for collection of condensates and oils for transport by truck to central processing facilities. Once enough wellpads are clustered in an area, installed pumps and liquid gathering lines can collect these hydrocarbons to central processing facilities. Produced gas is collected from well pads and sent to a centralized processing facility for cleanup to meet export or transport relevant transport specifications. As the number of well pads increases with field development, modular clustering of gas handling equipment often results. Inadequate capacity in the compression system or pipeline may result in venting or flaring of gas. Guarnone, et al. (Guarnone et al., 2012) state that a strong interaction between surface facilities engineering and drilling & completion activities is mandatory in order to minimize production fluctuation. In a climate where the oil is still valued significantly higher than natural gas, the design of surface facilities and their impact on flaring and environmental impact is often overlooked. The use of expandable, moveable gas-oil separation plans (GOSP) are not uncommon, and these tend to be much smaller in size than those typically associated with conventional production facilities. 4 ACS Paragon Plus Environment

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These themes seem to be consistent with the onslaught of news releases documenting development in recent shale plays. Additional complexity is provided by ongoing changes in economics associated with gas versus oil pricing; specifically, the grey zone relating to natural gas liquids (NGL) and the rapid decline of gas prices. According to Troner (Troner, 2013), specific production of NGL’s is currently heavily tied to what can be blended with stock tank oils for delivery to refineries since LNG specifications (LNG is exportable, crude oil is not) do not allow for marketable quantities of even the lightest LPG components (i.e. ethane, propane). In order to prevent delay in oil output, low priced (and likely low pressure) field gas has been flared (Curtis & Ware, 2012) and stock tank emissions overlooked. Increased attention to surface facility design details, including optimization in clustering of production facilities and early staging of gas handling equipment (requiring detailed engineering planning) is needed to minimize emissions to the environment, thus reducing gas vented per well. Technical Approach The fluids being produced from shales (particularly, Eagle Ford) are near critical. The initial reservoir fluid is either a volatile oil (high gas oil ratio (GOR)) or a retrograde condensate, depending on the reservoir oil. A range of fluids based on their compositions are first developed and their pressure-temperature diagrams are constructed. Production calculations (based on reservoir simulations) from previous studies show that liquid production and liquid recovery are enhanced in ultra-low permeability reservoirs when operating at a higher production pressure in the well (bottom-hole pressure). A key outcome of reservoir model development is the apparent paradox between reservoir modeling recommendations which cite the need to maintain bottomhole pressures (BHP) to maximize liquids production versus field operating practices which lower BHP to attempt to maintain liquids production over time. These process simulations are intended to identify what is at stake with respect to liquid quality and venting or flaring in terms of facility designs with uncertain ranges in BHP conditions. The implication of operating at a higher wellhead pressure on surface operations and on separator oil and gas production rates are examined by performing separator balances on all of the fluids.

While direct coupling of reservoir and facility modeling has been undertaken for conventional reservoirs, this seems premature for unconventional systems given the unknowns associated with depletion mechanisms. In this paper we have used surface facility modeling to explore impacts 5 ACS Paragon Plus Environment

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of surface facility design upon liquids production from shale and on gas quantities that are vented. As a starting point for evaluating impacts of surface facilities, process simulations using ASPEN v8.8 were undertaken. Fluid Descriptions The compositions for the near-critical Eagle Ford Fluids were adapted from Whitson et al. (Whitson & Sunjerga, 2012) as shown in Table 1. Table 1: Compositions and critical properties of various reservoir fluids Composition (% mole) Component Fluid 1 Fluid 2 Fluid 3 Fluid 4 Fluid 5 C1 70.62 69.1 67.57 66.05 64.52 C2 7.11 7.06 7.01 6.96 6.91 C3 5.97 5.93 5.89 5.85 5.81 iC4 1.15 1.11 1.07 1.025 0.98 nC4 1.96 1.93 1.9 1.87 1.84 iC5 0.9 0.87 0.84 0.81 0.78 nC5 0.96 0.92 0.89 0.855 0.82 FC6 1.37 1.35 1.33 1.31 1.29 C7+ 7.69 9.46 11.23 13 14.78 CO2 2.14 2.14 2.14 2.14 2.14 N2 0.13 0.13 0.13 0.13 0.13 O 117 176 233 285 337 Tc ( F) 3600 3912 4067 4074 3956 Pc (psi) C7+ Mol. Wt. 132 136 140 144 148 C7+ Sp. Gr. 0.776 0.777 0.778 0.779 0.780

Fluid 6 58.07 7.43 4.16 0.96 1.63 0.75 0.80 1.14 22.59 2.32 0.15 547 3459 178 0.840

Some of the mole fractions of the fluids are compared in Figure 4. As the fluids get heavier from fluid 1 to fluid 6, the most significant change is in the mole fraction of C7+ which increases from about 8% for fluid 1 to about 23% for fluid 6. Correspondinly, methane fraction decreases from about 70% to 58%.


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Figure 4. Compositions of the six reservoir fluids studied. The C7+ increases as the fluids become heavier. Fluid factors (PVT properties) controlling recovery of liquids from shale have been well summarized in recent literature, i.e. Wan, et al. (Wan et al., 2013), and Whitson and Sunjerga (Whitson & Sunjerga, 2012). Surface facility designs for unconventional liquid rich shale reservoirs need to make use of detailed C7+ fluid characterizations produced from reservoir PVT studies. Procedures for setting separator pressures typically involve trial and error calculations to identify separator conditions, which minimize the gas-oil-ratio (GOR) and formation volume factor while maximizing the quantity of stock tank oil. Recently, Ling et al. (Ling et al., 2013) have proposed an Equation of State (EOS) based method to maximize stock tank oil. They assume as an initial starting point that the EOS employed has been tuned to match available PVT data

for

the

reservoir.

The PT-diagram for black oil and condensate for the compositions given in the table 1 are shown in Figure 4 a and b. The diagrams were generated using the equation of state representation (Peng-Robinson equation of state). These calculations were performed using PVTsim thermodynamic program. At temperatures of 2500 F, 3000 F and 3500 F, fluids 1, 2 and 3 are in the condensate region (Figure 4a), while fluids 4, 5 and 6 at temperatures of 1000 F, 1500 F and 7 ACS Paragon Plus Environment

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2000 F are in the volatile oil region. These simulations (using PVTsim V20) ignored presence of water, which has other specific design considerations and impacts, to concentrate on differences in produced high pressure and low pressure gases, stock tank oils, and stock tank vapor emissions.

Figure 4. Pressure-temperature diagrams of the six fluids used in the calculations. (a) Condensates (b) Volatile Oils. Loci of critical points and the pertinent reservoir temperatures are shown. Fluids with temperatures to the right of the critical points are retrograde condensates while the fluids with reservoir temperatures to the left of the critical points are oils.

Bottom-hole Pressure Condition and Oil Recoveries Previous studies have shown that the liquid recoveries are significantly higher when the liquid producing wells are operated at higher bottom-hole pressure (Panja et al., 2015). An example plot of the variation of oil recovery with drawdown (difference between initial reservoir pressure and the bottom-hole pressure) is shown in Figure 5. These results were obtained by performing reservoir simulations on a low-permeability reservoir with a horizontal well and single vertical fracture. Black oil representation of the fluid was used. Figure 5 shows cumulative production as a function of drawdown for two reservoirs with permeabilities of 50 nano-Darcies (50 nD) and 100 nano-Darcies (100 nD) for two initial reservoir pressures. Drawdown is the pressure difference between the initial reservoir pressure and the bottom hole pressure. For the purposes 8 ACS Paragon Plus Environment

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of the calculation, the bottom hole pressure was assumed to be constant. It is seen that as the drawdown increases, the oil recovery – calculated as total amount of oil produced as a percentage of initial oil in place in the reservoir increases, but then starts decreasing. Thus, it is seen that for these low permeability reservoirs, there is an optimum recovery with respect to drawdown. This is true for condensate reservoirs also. Maintaining a higher BHP will mean a holding a higher wellhead pressure. The implication of this back pressure on the reservoir on produced oil quality and specifically on associated gas production are investigated.

Figure 5. Oil recovery as a function of drawdown – which is the difference between the initial reservoir pressure and the bottom-hole pressure. Separator Studies Maintaining a higher wellhead pressure for better oil and condensate recoveries may require changes in separator conditions at the surface. One solution is to use a two-stage separator instead of a single stage separator. The consequence of using two stage versus one stage separators on oil quality and gas rates was examined using PVTsim. The schematic diagrams of a single stage separator and the two stage separator are shown in Figures 6 and 7 respectively. Feed rates in all the calculations are 1,000 lbmoles per hour of the specified fluid. Separator conditions were set at the “typical” pressures reported to be currently found in the field, with temperatures typical for production schemes involving Eagle Ford or Bakken fluids.


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Figure 6. Single stage separation flow sheet.

Figure 7. Two stage separation flow sheet. HP stands for high-pressure and LP for low pressure. The effect of using these arrangements on liquid and gas rates is summarized in Table 2. Three stream are shown – gas production, liquid production and vent gas from the stock tank. In the case of two-stage separation, the two gas streams (high-pressure and low pressure) are combined and reported as one.


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Table 2. The effect of employing a two-stage separator system on liquid and gas rates. Gas (MSCFD)

Fluid 1 Fluid 2 Fluid 3 Fluid 4 Fluid 5 Fluid 6

Single Stage 7793 7575 7361 7152 6945 6158

Two Stage 8907 8767 8632 8498 8365 7407

Stock Tank Oil (BPD) Single Stage 1085 1335 1595 1864 2145 3519

Two Stage 1129 1379 1640 1910 2191 3562

Tank Vapor Vent (MSCFD) Single Stage

Two Stage

333 375 414 451 486 537

112 119 125 130 134 135

It is seen from the table that the the tank vapor vent amounts (some percentage of which are flared) decrease dramatically as we go from one stage to two stages. The total amount of oil production increases as well. The gas production increases slightly. The net gains in oil and gas production and decrease in vent amounts in percentages for two stage versus one stage are summarized in Figure 8. In general, the percentage gains are slightly better as we go from condensates to oils, but gains in the range of 60-70% are realized in reducing the amount of gas produced from the stock tank. Densities of the stock tank oils improve slightly as well and this is shown in Figure 9.


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Figure 8: Change in hydrocarbon production and vent gas in two stage separation compared to single stage separation

Figure 9. Change in Stock Tank gravity in two stage separation compared to single stage separation.


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The oils after two stage separation do contain additional amount of lighter components and it is important to establish that they do meet the new standards for vapor pressures established by the North Dakota Oil and Gas Commission (Industrial Commission of North Dakota, 2014). The standards require stock tank liquid vapor pressures to be less than 13.7 psi. The vapor pressures refer to the measurements of Reid Vapor Pressures (RVP). RVP is measured using an ASTM standard (ASTM International, 2014). Calculations of RVP using stock tank compositions are complicated. Equilibrium pressure of an air saturated product with an air-filled vapor chamber with four times the volume of the liquid may be used to simulate or calculate the RVP (Lord et al., 2015). The stock-tank liquid compositions for all of the fluids with their gravities and molecular weights are shown in Table 3. The API gravities of these fluids range from 42-60. RVPs calculated for all of the fluids are reported in the last row of Table 3. As expected, RVPs increase for stock-tank oils after the two-stage separation. However, even the lightest of the fluid (Fluid 1) meets the RVP threshold of 13.7 psi. RVP values range from about 7-10 psi for single-stage separators and 9-12 psi for two stage separation. The two-stage separation would require higher initial investment. For the generic case of 1000 mol/hr of Eagle Ford Reservoir (condensate) fluid and process flow schemes per Figures 6 & 7, the typical sizing and relative costs are summarized in Table 4 for single and two stage separator schemes.


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Table 3. Compositions of the stock-tank oils after single stage or two-stage separation and calculated Reid Vapor Pressures (RVP). The RVP values with two-stage separation do increase, but are below the 13.7 psi regulated by North Dakota and a few other states. Components Stock Tank Liquid Composition (mol. %) Fluid 1 Single Two Stage Stage N2 CO2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9 C10+ Molecular Weight API Gravity RVP (psi)

Fluid 2 Single Two Stage Stage





0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.028

0.020

0.030

0.023

0.031

0.025

0.033

0.028

0.035

0.031

0.046

0.046

0.145

0.055

0.152

0.062

0.159

0.069

0.166

0.076

0.172

0.083

0.170

0.094

0.352

0.365

0.370

0.401

0.386

0.433

0.401

0.462

0.416

0.489

0.509

0.650

2.354

3.416

2.395

3.487

2.424

3.525

2.445

3.543

2.458

3.543

1.830

2.619

1.483

2.111

1.409

1.974

1.335

1.842

1.256

1.709

1.179

1.582

1.061

1.376

3.832

5.218

3.636

4.858

3.452

4.535

3.281

4.246

3.120

3.984

2.452

3.015

3.798

4.434

3.362

3.868

2.998

3.411

2.690

3.032

2.424

2.711

1.842

2.017

4.789

5.362

4.143

4.587

3.659

4.016

3.240

3.531

2.883

3.125

2.171

2.316

10.358

10.303

8.843

8.807

7.702

7.679

6.811

6.798

6.090

6.085

3.866

3.875

18.543

17.615

17.960

17.189

17.312

16.661

16.661

16.106

16.027

15.551

11.939

11.703

14.168

13.345

14.005

13.304

13.740

13.136

13.430

12.904

13.096

12.636

10.412

10.169

10.616

9.973

10.736

10.175

10.742

10.246

10.678

10.238

10.568

10.175

9.009

8.786

29.535

27.782

32.959

31.265

36.060

34.422

38.908

37.325

41.531

40.004

54.692

53.335

116.2

113.1

120.7

117.7

125.1

122.2

129.3

126.6

133.6

130.9

162.9

160.3

60.09

61.56

59.00

60.27

58.09

59.21

57.29

58.29

56.58

57.47

41.83

42.41

10.03

12.36

9.75

11.96

9.44

11.61

9.17

11.26

8.91

10.91

7.24

8.84


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Table 4. Relative Cost Difference for Two Stage and Single Stage Separation (excluding any additional compression costs for Single Stage). Two Stage Separation (HP, LP) Single Stage HP (Vertical) LP (Horizontal) Separator (Vertical) Shell TL-TL (Ft) 24 24 24 Shell OD (Ft) 5 4.5 5 Shell Steel (Ton) 25.2 2.1 7.3 Equipment Cost* $ 192,210 30,767 75,061 Total Installed Cost** 1,056,912 355,789 $ Relative Total Cost 3 2 Stage/1 Stage *Estimated Costs per Towler and Sinnott, Chemical Engineering Design, 2nd Edition, Eq. 7.9, page 321, carbon steel construction, 2010 – Gulf of Mexico Basis. **Total Installed Cost corrected to 2016 and 4.74 installation factor. It is thus observed that the two-stage separation would require an increased upfront investment of 3:1 relative to the single-stage option. The two stage operation also creates an intermediate pressure gas stream which may need additional dehydration/compression. Additionally, we note that two stage separation using these pressures is not possible when employing relatively low BHP conditions (~500 psia). All of these considerations will need to be balanced with the fact that the gas flared could be reduced to almost a third by using the two-stage separator options.

Impact of Operating Conditions on Flow Regimes The surface and sub-surface connection was further explored by looking at a typical condensate fluid to explore operability of the surface facility design under variable conditions. Various processing units were assembled together to separate gas, liquid condensate and water from the feedstock from well head. Typical well bore dimensions, gathering line sizes, and facility process configuration were simulated using ASPEN v8.8. The simulator flowsheet for the APSEN model is shown in Figure 10. The units and operational conditions are summarized in Table 3. The fluid feed from well header (gathering line from many wells typically 15-30 depending on location and facility) is cooled in well stream cooler to a lower temperature below dew point pressure. A pressure control valve is used to maintain the back pressure to avoid liquid dominating flow in the pipe line before entering the high pressure (HP) separator. The phase separation namely, gas, liquid condensate and water takes place in the HP separator. Water is 15 ACS Paragon Plus Environment

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routed from the bottom of the separator to produced water processing unit before discharging to environment. All streams of water from various vessels are collected in a degasser tank where dissolved gas is liberated and is sent to compressor unit. The high pressure gas from HP separator is routed to high pressure scrubber to get rid of any liquid phase such as condensate and water. The gas from HP scrubber is then compressed for transportation to the nearby gas processing facility. Series of compressors are often required to boost the discharge pressure which depends on the length of the pipe line and the well head pressure. Liquid condensate from HP separator flow to intermediate pressure (IP) separator through a throttle valve with other condensate streams to remove carry over water and any dissolved or flashed (or vaporized) gas. Liquid condensate from IP separator is then pumped to condensate processing unit. Positive displacement pump is used to generate high pressure. The efficiency of gas-compressor is greatly affected by the presence of any liquid. A knock out drum (KOD) is installed in the inlet stream of compressor to remove any traces of liquid before the gas entering the compressor. Although the basic purposes of many vessels such as separator, scrubber, stripper, KOD etc. are similar, their internal structure and operating conditions are different. Part of the gas could be used to generate electricity for the facility. For the Aspen simulation, reservoir conditions were taken to be 6500 psia, and 200oF. The wellbore design simulated involved six wells, each designed for 40.5 MMSCFD of gas and 2500 BPD of condensate. The ASPEN simulation modeled one well as a 5” wellbore, with 12,000 ft vertical and 4,000 ft horizontal sections as shown in Figure 11. The other five wells were not specifically handled, just totaled. Steady state flow was assumed through the process flow system. Beggs and Brill’s (Beggs & Brill, 1973) frictional correlations and liquid hold up correlations were used to calculate pressure drop in multiphase flow in pipe Wellhead choke pressure was changed with time i.e., with depletion of reservoir to allow wellhead fluid flowing through process coolers and pressure letdown before arriving at the HP separator. It is noted that this simulated facility represents a central processing facility that would gather feed from multiple wells. This was done to demonstrate the impacts of changing production parameters for realistic conditions. PT diagram analysis shows that this facility design provided a path on the PT diagram which closely followed a line of constant vapor/liquid mole fraction of ~0.85, making


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sizing (and subsequent operation) of multiphase piping and equipment fairly uniform in character.


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Figure 10. Conventional condensate field process simulation flow sheet – ASPEN v8.8


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Table 3: Selected Important Unit Operations in the Process diagram Acronym

Full Name

Function

HPSEP HPSCRUB IPSEP DEGASDR STRIPPER LIQCOOL GASCOMPR GASKODR WELLCOOL GASCOOL

High Pressure Separator High Pressure Scrubber Intermediate Pressure Separator Degasser Drum Stripper Liquid Cooler Gas Compressor Gas Knock Out Drum Well Fluid Cooler Gas Cooler

Separate well fluid into gas, oil and water phases Separate water and oil from gaseous phase Separate gas, oil and water from oil phase Remove dissolved gas from water phase Remove dissolved gas from oil phase Cool oil though heat exchanging Compress gas to higher pressure Remove vaporized hydrocarbon from gas phase Cool well fluid Cool gas phase


Conditions Temperature Pressure O ( F) (psig) 86 700 70 450 75 170 75 50 33 stage 140 30 470 150 450 125 150 440

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Figure 11: Subsurface flow modeling. Different flow regimes obtained by performing multiphase calculations are shown in Table 4. As summarized in Table 4, lowering bottom-hole pressure (BHP) by reducing wellhead choke pressures, created choke flow by increasing liquid fractions and flow velocities. As the pressure is progressively reduced from the horizontal inlet to vertical inlet to choke, flow regimes shift from vapor to vapor and mist. Table 4. Well subsurface flow modeling with ASPEN v8.8 Pressure (psia) Flow Type Horizontal Inlet

5500 4500 3000 2300

Vertical Inlet 5430 4427 2882 2141

Well Head 3556 2709 1301 300

Choke 2415 2415 1015 15

Horizontal Inlet Outlet Vapor Vapor Vapor Vapor Mist Mist Mist Mist

Vertical Inlet Outlet Vapor Vapor Vapor Mist Mist Mist Mist Mist

Horizontal Inlet Liquid Hold up 0 0 0.10 0.09

These transitions create unfavorable flow regimes in surface gathering lines. The HP separator was set low enough that the process facility did not see any operational impacts beyond reduction in total flow associated with choke flows. Small reductions in BHP, and associated gathering line pressures resulted in operation of the LPG stripper and gas compression within 20 ACS Paragon Plus Environment

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acceptable design parameters. Fallout of liquid condensates at the lowest BHP conditions for all six wells reduces stock tank oil (STO) production to levels which prevent operation of the LPG stripper within acceptable design parameters (dry trays). While not demonstrated by this initial simulation work, further reducing BHP / wellhead pressure would require lower first stage separator pressures to maintain flow rates and this would lead to liquid carryover /entrainment. Without additional scrubber vessels as provided in this design, concerns with liquids impacts to gas compression could be observed.

This modeling confirmed the ability to review facility operation for possible operating scenarios involving production from unconventional reservoirs even without employing “dynamic” simulation and directly coupled reservoir and facility models. It is clear that operational parameters such as separator pressure, and wellhead pressure can have an impact on reservoir production and that surface controls (selected operation pressures) may in turn impact subsurface operations. Surface operations may also be constrained by flow conditions created sub-surface or in gathering line systems.

In the low oil price-environment, management of unconventional resources may require development of optimal separator staging concepts, which allow for any needed reduction in operating pressures to offset decline in production rates. This might include the option to shift older lower rate wells from high pressure to lower pressure initial separation stages. This could effectively use additional CAPEX in piping design (more manifold options) rather than building larger high-pressure separators, which are then run at low pressure later in the life cycle of the facility. In addition, revised economic pipe diameters for multi-phase flow which include total life cycle operation (range in operation pressures and flow regimes) may need to be put in place. Process design heuristics to guide preliminary design of surface facilities based on initial reservoir fluid PVT characterizations will also be needed because of the large environmental footprint due to wasted and flared gas. These proposed heuristics should be benchmarked against available surface facility design performance data.

Future tight oil production should take advantage of cutting edge technologies which evolve from process intensification for combination of separation and treating steps to produce natural 21 ACS Paragon Plus Environment

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gas, and other light end “products” at the wellhead/well pad. This can help make tight oil a more sustainable resource, allow regional development of other industries which are not currently economic, and help bridge the gap to future sustainable energy sources.

Conclusions Separator facility design decisions for unconventional production of liquids from shale reservoirs are more difficult due to questions around the nature of the actual reservoir fluid in place. It is now generally understood that, when possible, holding a higher backpressure on the well helps improve liquid recovery and in some instances liquid rates. To put this production strategy in place, a two-stage separator may be required. Using a two-stage separator versus one stage results in approximately two-thirds reduction in vent gas that will need to be flared. From a technical standpoint, this creates a win-win scenario, so long as the produced liquid meets new regulations concerning vapor pressures. Reid Vapor Pressure (RVP) values of stock-tank liquids after two-stage separation increased to about 9-12 psi depending on the volatility of the fluid being produced (from 7-10 psi for single-stage separated stock-tank liquids). The highest RVP values were still below the threshold of 13.7 psi specified by some state regulatory agencies (North Dakota, for example). Selection of multi-stage or single stage gas-oil (and water) separation schemes must work tradeoffs associated with CAPEX and OPEX inherent with each design. Preliminary economic evaluation showed that two-stage selection would require a 3:1 investment compared to single stage. Often this is heavily influenced by local geography, and the proximity of well pad clusters. Surface process facilities for unconventional production of liquids differ in general size and character (are smaller) from facilities for conventional production operations. A key design concept to be continually worked with is the need for close interaction between facility engineering and drilling and completion activities. Modular facilities which are movable for “plug-n-play” operations, which are all transportable by road are preferred over onsite stick built facilities. Selection of operating well coke pressures and resulting BHP must be made with both long term hydrocarbon recovery and facility design limits in mind. Careful attention to flow regimes in multiphase well bores and gathering lines will help avoid flow bottlenecks.


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References Beggs, D. H. & Brill, J. P. (1973). A Study of Two-Phase Flow in Inclined Pipes. Journal of Petroleum Technology 25. Curtis, T. & Ware, T. (2012). Restricting North Dakota gas-flaring would delay oil output, impose costs. Oil & Gas Journal, 96-106. Guarnone, M., Rossi, F., Negri, E., Grassi, C., Genazzi, D. & Zennaro, R. (2012). An unconventional mindset for shale gas surface facilities. Journal of Natural Gas Science and Engineering 6, 14-23. Hoffman, T.B., Sonnenberg, S., Kazemi, H. and Cui, Q. (2014) The Benefits of Reinjecting Instead of Flaring Produced Gas in Unconventional Oil Reservoirs, Unconventional Resources Technology Conference, Denver, Colorado, August 25-27, 2014. Industrial Commission of North Dakota, 2014, ndustrial Commission Adopts New Standards to Improve Oil Transportation Safety, Commission Order 25417, Oil and Gas Division. Ling, K., Shen, Z., He. J. and Peng P. (2014)A Review of Enhanced Oil Recovery Methods Appiled to the Williston Basin, URTeC: 1891560, Unconventional Resources Technology Conference, Denver, Colorado, August 25-27, 2014. Ling, K., Wu, X., Guo, B. & He, J. (2013). New Method To Estimate Surface-Separator Optimum Operating Pressures. Oil and Gas Facilities 2. Lord, D., Luketa, A., Wocken, C., Schlasner, S., Aulich, T., Allen, R. and Rudeen, D., 2015, Literature Survey of Crude Oil Properties RElevant to Handling Fire Safety in Transport, SAND2015-1823, DOE/DOT Tight Crude Oil Flammability and Transportation Spill Safety Project, Sandia National Laboratories. Panja, P., Conner, T. and Deo, M.D., (2015). Factors Controlling Production in Hydraulically Fractured Low Permeability Oil Reservoirs, In Press, International Journal of Oil, Gas and Coal Technology. Troner, A. (2013). Natural Gas Liquids in the Shale Revolution. The James A. Baker III Institute for Public Policy, Rice University. Wallace E. M. and Ehlig-Economides, C.A., (2015). Associated Shale Gas: From Flares to Rig Power, SPE-173491, Paper Presented at the SPE E&P Health Safety, Security and Environmental Conference, DEnver Colorado, 16-18 March 2015. Wan, J., Barnum, R. S., Digloria, D. C., Leahy-Dios, A., Missman, R. & Hemphill, J. (2013). Factors Controlling Recovery in Liquids Rich Unconventional Systems. International Petroleum Technology Conference. Beijing, China: International Petroleum Technology Conference.


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Werner, A.K., Vink, S., Watt Kerrianne and Jagals, P., 2015. Environmental Health Impacts of Unconventional Natural Gas Development: A Review of the Current Strength of Evidence, Scince of the Total Environment, 505(2015) 1127-1141. Whitson, C. H. & Sunjerga, S. (2012). PVT in Liquid-Rich Shale Reservoirs. SPE Annual Technical Conference and Exhibition. San Antonio, Texas, USA: Society of Petroleum Engineers.


Reducing Gas Flaring in Oil Production from Shales - Energy & Fuels

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