SPE 9593 Integration of Geologic and Dynamic Models for History Matching, Medusa Field J. Lach, K. McMillen, and R. Archer, Knowledge Reservoir L.P.; J. Holland and R. DePauw, Murphy E&P Co.; and B.E. Ludvigsen, Scandpower P.T. Copyright 25, Society of Petroleum Engineers This paper was prepared for presentation at the 25 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 12 October 25. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 3 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 7583-3836, U.S.A., fax 1-972-952-9435. Abstract Medusa Field in the Gulf of Mexico produces from turbidite sandstone reservoirs at depths between 1, and 14, feet. Production from the field commenced in December 23, and six wells are producing at a rate of 4, BOE/Day. Well A-3 is producing from the T4B reservoir at average oil rates in excess of 1, STB/Day. The late Miocene T4B reservoir was deposited in a turbidite channel/levee environment with extensive thinbedded levee and isolated massive sand channel-splay facies. Stratigraphic cross sections and seismic amplitudes show rapid lateral change from levee to channel-splay facies. Depositional slopes, consisting of the east-facing levee flank and westfacing regional slope, and syn-depositional normal faulting control the location and thickness of channel-splay deposition. Conventional core in one T4B well provides information on depositional facies, reservoir properties and rock compaction. The decline of reservoir pressure early in the producing life indicated that well A-3 was connected to a smaller oil volume than estimated from pre-production models. However later performance, the ability to sustain oil flow rate and a slowing of the rate of reservoir pressure decline, suggested communication between the higher quality channel-splay and levee facies and a larger OOIP than indicated by the early performance. The eventual rise in producing gas-oil ratio and the onset of minor water production were also affecting later well performance. Simulation history matching commenced using preproduction reservoir characterization models with the objective of forecast well A-3 production and evaluating the potential for a previously planned second well completion in the zone. Traditional history matching using the original static model was not satisfactory. MEPO, an optimization tool for assisted history matching, was used to complete the history match study. Multiple equiprobable history matches were obtained varying fault and facies transmissibility, fluid PVT, rock compaction curves, and critical gas saturation. The reserves and production profile risk for a future well completion have been evaluated with a range of the history match results. Medusa Field Description Medusa Field is located in the Gulf of Mexico approximately 11 miles southeast of New Orleans in 22 ft of water (Figure 1). The field extends over blocks MC 538 and MC 582 in the Mississippi Canyon area. The discovery well, MC 582 #1OH, reached TD of 16,95 ft MD (15,621 ft TVD SS) in September, 1999. Murphy Oil Exploration and Production Company is operator of Medusa Field with 6% interest. Field partners include ENI Petroleum Corporation with 25% interest and Callon Petroleum Operating Company with 15% interest. Subsequent drilling delineated the field and showed that hydrocarbons exist across a major fault/salt-weld structure to the west. Three major reservoir intervals have been identified in addition to several minor reservoir sands. The major intervals are the T1B, T4B and T4C. The Medusa Field was developed with the construction of a dry tree SPAR. The production facility has processing capacity for 4, STB/d of oil, 11 MM SCF/d of gas and 2, STB/d of produced water. Six wells, A-1 through A-6 were initially completed targeting the T1B, T4B and T4C zones. The development plan includes future re-completions and sidetracks to adequately drain all reservoirs. Production from the Medusa Field commenced in December 23. The late Miocene T4B Sand is one of three major reservoirs in Medusa Field. Other major pay sands include the T1B (Pliocene) Sand and older late Miocene T4C Sand (Figure 2). The T4B Sand occurs at a depth of about 13, ft TVD SS and is located east of a salt weld that bisects Medusa Field. The T4B pay sand is located in a structural low and is a stratigraphic trap (Figure 3). Reservoir lithologies consist of thin-bedded sand and shale facies and massive sand. Seismic amplitude and impedance strength delineate the extent of massive sand of the T4B reservoir in this syncline. A single large southwest-dipping normal fault occurs at the west side of the reservoir and several parallel minor faults cut the reservoir sand. An east-west trending, north-dipping fault occurs at the northern end of the massive sand section.
2 SPE 9593 T4B Reservoir Geology The T4B reservoir was mainly deposited in a channel/levee depositional setting (Figure 4). The A-1 and A-6 wells penetrated thick intervals of thin-bedded levee facies, whereas the MC582#1 and A-3 wells encountered a time-equivalent massive sand reservoir. The thick levee facies flanked a bypass (feeder) channel, interpreted to have been located west of the wells. The salt ridge to the west of the channel controlled the channel and main constructional levee. The massive sand encountered in the MC582#1 and A-3 wells is interpreted as a minor sheet or channel splay sand that was deposited as channel avulsion diverted turbidite sedimentation to the levee flank. This channel splay was confined by the east-facing slope of the main levee, a west-facies regional depositional slope and west-dipping normal fault. An additional splay sand is interpreted farther south based on seismic amplitude and impedance strength. Stratigraphic correlation of the T4B Sand shows the lateral change in facies from thin-bedded sand and shale of the levee depofacies in the A-6 well to the massive channel-splay sand in the MC582#1 and A-3 wells (Figure 5). The splay sand quickly becomes shalier to the southeast with some thinner beds in the A-3 well. This rapid facies change is consistent with the small aerial extent of the T4B channel-splay sand. The thin-bedded levee facies in the A-6 well was deposited over a greater time than the massive channel-splay sand. It correlates only to the upper part of the levee interval, demonstrating that the splay sand was deposited in a shorter time compared to the levee facies. Reservoir properties for the T4B Sand from petrophysical and conventional core analyses are summarized in Table 1. The results show the differences between depofacies in that the massive channel-splay sand in the MC582#1 well has high net to gross, high porosity and low water saturation whereas the levee facies in the A-6 well has low net/gross and porosity. Average water saturation of the levee depofacies is high at 43%; however, the thin-bedded character of this reservoir results in averaging of properties between sand and shale so that sand-only properties are difficult to determine. The A-3 well, which is shalier and has some thin beds compared to the MCV582#1 well, has reservoir properties intermediate between the MC582#1 and A-6 wells. T4B Reservoir Production Performance Well A-3 is the only current production well in the T4B zone. The well was perforated over the interval of 13,196 to 13,241 feet TVD with a frac-pack completion. Production from the well commenced in March 24. Over a period of approximately one month, well A-3 was ramped up to an oil rate of 9,9 STB/Day at a drawdown pressure of 75 psi. Historical oil rate, water cut, gas-oil ratio (GOR) and bottom-hole pressure for well A-3 are shown in Figure 6. A peak oil rate of 14, STB/Day has been achieved, and the well has produced cumulative oil and gas of 2618 MSTB and 334 MMSCF through 435 days. Hurricane Ivan in September of 24 resulted in a shut-down of production for 3 days. The producing GOR has been rising in well A-3 since early 25 and low but rising water cut has been observed in recent months. Permanent down-hole pressure gauges have recorded continuous data through-out the period permitting the analysis of well productivity index (PI), operational drawdown, and effective oil permeability (Ko) and Skin from pressure transient analysis. The historical A-3 well PI and drawdown pressure are shown in Figure 7. Productivity index has typically ranged from 15 25 STB/Day/psi. However, a significantly increased PI of 43 STB/Day/psi was observed immediately after the 3 day hurricane shut-down. The increase of producing GOR has led to a decline of liquid PI since January 25. Flowing drawdown pressure is constrained operationally to avoid failure to the frac-pack sand control completion. The drawdown in well A-3 was constrained to between 5 8 psi under typical operating conditions. With the onset of increasing GOR, the drawdown pressure has been increased to approximately 1 psi to maintain oil rate. Pressure transient analysis of shut-in periods is used to observe the completion Skin and effective oil permeability changes. The T4B reservoir is highly compacting as measured in whole cores. With the decline of reservoir pressure, net effective overburden stress increases resulting in significant reduction of the porosity and permeability. Historical Skin and Ko is shown in Figure 8. Effective oil permeability has declined approximately 55% since the start of production. The decline is attributed to both rock compaction and the liberation of gas in the reservoir. The Skin factor ranged from +6 to +8 during the early production period in well A-3. A noticeable decrease in Skin was observed just prior to the hurricane shut-in and concurrent with a large increase of oil rate from 1, to 14, STB/Day. Material balance calculations were made after approximately 275 days of reservoir performance. The results suggested that well A-3 was connected to an oil volume (OOIP) of between 12 15 MMSTB. The connected OOIP was less than anticipated from pre-production simulation models. Questions were raised about the influence of facies boundaries between high quality splay sands and the surrounding levee and overbank sands. The history matching of well A-3 performance in the pre-production model was used to address connected volume and the impact/potential for a future completion in the zone. History Match of Reservoir Performance The combination of small OOIP and highly productive wells in many of the deepwater Gulf of Mexico reservoirs results in rapid depletion and significant lessons learned during the first year of production. It is common practice for operators to develop pre-production reservoir simulation models incorporating all exploration, appraisal and development well drilling data. The models are used immediately from the outset of production for reservoir management and the validation of reserves and production forecasts. Traditional history matching includes the use of a single static model realization and the modification of reservoir rock/fluid properties and boundary conditions (aquifer and facies/fault transmissibility) in an attempt to achieve the best match. The resulting single history match is used to make a
SPE 9593 3 single forecast realization. Attempts to achieve a viable history match for the T4B reservoir were unsuccessful. Introduction to MEPO Successful history matching for the Medusa T4B reservoir was achieved using MEPO, Multipurpose Environment for Parallel Optimization. MEPO is a flexible framework for history matching which, based on your simulation model and uncertainties in input parameters, uses optimization techniques and multiple simulation runs to identify a range of equal probable solutions all matching known production history. Hundreds of simulations are run varying a determined set of parameters within a defined range of values. All uncertainty parameters can be included, and it is not necessary to reduce the solution space initially. MEPO runs the full simulations instead of using equations to define response surfaces. The user defines object functions or match parameters and their relative weighting. The production history can also be divided into time periods for differing the weighting of match parameters at different times. A range of both local and global optimization methods are available within MEPO including Evolution Strategy, Genetic Algorithm, Bayesian Analysis, and Experimental Design. As simulation cases are run, the MEPO software provides the interface to review model results quickly including the optimization parameter (Figure 9). Changes to the strategy of matching parameters can be changed during a cycle of simulation runs. Medusa T4B History Matching Parameters The A-3 well performance is affected by the following: reservoir faulting, facies boundaries, bubble point pressure, rock compaction, 3-phase relative permeability, and to a minor extent the presence of aquifer. The combination of faulting and facies boundaries is modeled by changing the transmissibility at faults #2 and #3 and the location of fault #1 (Figure 1). The north bounding fault #1 is moved north-tosouth up to 8 feet from the original estimate from seismic interpretation. All three faults are simplified as straight lines to permit the isolation of an area around A-3 thus minimizing the connected oil volume. The eastern boundary of the reservoir is a stratigraphic trap. In an attempt to match the increasing GOR in A-3, the bubble point pressure and critical gas saturation are variable in the MEPO runs. Original reservoir pressure is 945 psia at a datum depth of 13,148 feet TVD SS. Fluid samples were obtained during field appraisal using the Schlumberger MDT tool. The measured bubble point pressure, corrected for oilbased mud contamination and separator conditions, was 53 psia. A post production oil sample was taken and a PVT study was conducted using separator samples from the A-3. In this subsequent PVT study, a bubble point pressure of 6735 psia was measured, significantly different from the pre-production estimate. Within the MEPO runs the bubble point is permitted to vary from 57 to 77 psi during simulation history matching. The critical gas saturation is varied from. to.2 by end-point scaling during history matching. The T4B reservoir is a highly compacting rock due to the over-pressured initial conditions and the unconsolidated rock matrix. Lab measurements on conventional whole core samples were used to quantify the reduction of porosity and permeability with increasing net effective stress. Ranges of variability were applied to the lab data during history matching with MEPO. Figure 11 shows the lab data used in pre-production simulation (solid lines) and the variable ranges of the data applied during history matching. The permeability reduction curve from lab data was quite pessimistic and therefore only less permeability reduction was considered in the history matching. Both more and less pore volume compressibility was considered during matching. Oil viscosity was also varied ±3% off the base PVT lab data. Finally, the presence of an aquifer was implemented in some simulation cycles by placement of an oil-water contact in the bottom of the reservoir but with small connected water volume. History Matching Results Approximately 1 simulation runs were made over a period of two weeks for history matching the A-3 well performance. Simulations were run in 7 cycles, and each cycle explored a unique strategy for the attempted history match. Multiple acceptable history matches were achieved. MEPO provided the flexibility to run, control, and review this large number of simulations within a short time. The 436 days of producing history was divided into three time periods to permit Partial optimization of an objective function (match parameter). The Global optimization value represents the quality of match over the entire history. The time periods considered were: initial 16 days of production, the period surrounding the 3 day hurricane shut-down, and the remaining history. Weighting factors are applied in the strategy file to permit the focusing on particular matching parameters and during different partial periods. Bottom-hole pressure and gas-oil ratio were the primary focus of history matching. The results of two history matches versus measured data for pressure and GOR are shown in Figure 12. The differences in these matches are as follows: 1. History match #5 (HM5) is a less connected reservoir with higher bubble point pressure (7675 psia). History match #7 (HM7) has better reservoir connectivity and lower bubble point pressure. All history matches required the bubble point to be higher than measured in the lab 2. HM7 assumes a more compressible rock than HM5. All matches are achieved with less rock compaction and permeability loss than observed from core studies. 3. The case of HM7 has a small aquifer and matches the low produced water cut. Case HM5 and other matches assume the low producing water cut of ~4% is minor extraneous water from reservoir depressurization. 4. All history matches required reservoir connectivity between the splay and levee regions. Therefore, a future well completion in A-6 should be somewhat pressure depleted and in communication with well A-3. Overall the history matching indicated that a significant level of communication exists between the high quality splay and more laminated levee sands. There were no suitable history matches in a confined reservoir with low
4 SPE 9593 transmissibility across faults and/or facies boundaries. The results from material balance calculations after 6 months of production suggested that well A-3 was producing from a smaller than modeled connected oil volume. This effect is often observed in over-pressured turbidite reservoirs where the early production-pressure history is indicative of the higher quality facies. Afterwards, sufficient pressure differential is present in the reservoir to permit flow from across faults/facies boundaries. The history matching has provided confidence in a connected OOIP of 41 MMSTB. An additional zone of OOIP, assumed to be disconnected from the main area due to appraisal MDT pressure data, exists to the north of wells A-3 and A-6. It is possible that boundaries separating the northern compartment, mapped as faulting, could be broken down due to the high reservoir pressure depletion. This case was not modeled in the MEPO history matching process. Reservoir Management and Simulation Forecasts The results viewer in MEPO can be used to select a specific history match and to export the parameter used in the match for making predictions. For the history matches previously shown, prediction runs were made to forecast ongoing production from A-3 and a future completion in A-6. The resulting cumulative oil and gas versus time is shown in Figure 13. The predicted total equivalent oil and gas is 12. MMBOE for history match #7 and 11.7 MMBOE for history match #5. The results are not significantly different in terms of total reserves in this case. However, the prediction of peak gas rate and produced water volume can be significant for development or tie-back of a deepwater reservoir/well. The predicted oil recovery factor for the T4B reservoir is 26% of OOIP for both history matches shown. Gas recovery is predicted at 19% of original dissolved gas in-place for history match #7. Although well A-3 is affecting the entire main area, the second completion in well A-6 is probably required to effectively drain both the levee and splay facies regions. relative permeability. The permeability reduction from rock compaction does not appear to be as severe as suggested from laboratory measurements. 5. Forecasts of future production and the expected recovery from an additional reservoir completion were evaluated in two of the history matches. The ultimate reservoir recovery did not vary significantly between the two cases. However, the oil, gas and water rates were variable which can be significant for development planning in a deepwater setting. Acknowledgements The authors would like to thank the Medusa Field owners, Murphy Exploration and Production, Inc., Callon Petroleum and ENI Petroleum, Inc., for permitting this work to be published. The petrophysics for this work were calculated by K. Jay. The seismic interpretation was by T. Becker and D. Reiter. The team leader for the overall reservoir modeling effort was L. Wilson. Conclusions Conclusions derived from this work are as follows: 1. MEPO is an assisted history matching tool used successfully to find multiple history matches in a quick, two weeks study. Over 1 simulation were run to evaluate a range of reservoir uncertainties. 2. The T4B reservoir in Medusa Field is a stratigraphically confined syncline. History matching has confirmed the reservoir connectivity across faulting and channel-levee-splay facies boundaries. 3. Material balance estimates of connected oil volume based on early production performance can be pessimistic in over-pressured and stratigraphically complex turbidite environments. 4. The effective oil permeability has declined by over 5% based on pressure transient analysis. Much of the decline is due to production below bubble point, increasing GOR and the resulting effects on 3-pahse
SPE 9593 5 Well Top Res Base Res Gross Net Pay Net/Gross Phi e Vcl Swe Klog TVD SS ft TVD SS ft TVT ft TVT ft md MC582#1 13219 13281 54 54 1..31.6.18 643 MC582#2BP1(A-3) 13124 13169 5 43.86.26.14.31 396 MC582#5(A-6)) 12521 12857 336 95.28.25.27.43 63 Table 1 Average reservoir zone properties, T4B Sand Gulf of Mexico Medusa Field Mississippi Canyon Blocks MC538 / MC582 Figure 1 Medusa Field location map, Mississippi Canyon area, Gulf of Mexico
6 SPE 9593 Figure 2 Stratigraphic column, Medusa Field A-1 T4b Reservoir MC538 Medusa Field Platform MC539 A-6 Shell 583#1 MC582#1 A-3 Mariner MC583#1 MC582 Salt MC583 Figure 3 Structure map, T4B Sand
SPE 9593 7 LATE T4B DEPOSITIONAL ENVIRONMENTS SALT RIDGE Channel Avulsion Active Channel A-6 A-1 Levee/Overbank Sands/Shales A-3 MC 583#1 Levee/Overbank Deposits Proximal sheets Sandy Channel Levee/Overbank Sheet Shale Stacked sheets bounded on the east byadowntothewestfaultand on the west by older levee deposits Distal sheet sands Levee/Overbank Deposits? Seismic Amplitude possibly equivalent to T4b Fan Complex? Figure 4 Depositional model, T4B Sand NW STRATIGRAPHIC CROSS SECTION T4B MC582#3 (A-6) MC582#1 GR TVD GR TVD SS SS ft ft 15 26 15 26 SE MC582#2BP1 (A-3) GR TVD SS ft 15 26 1255 1325 1315 126 Depofacies 1265 Thin-bed levee Splay sand 127 1275 128 1285 Figure 5 Depofacies cross section, T4B Sand
8 SPE 9593 Oil Rate (STB/Day) 16, 14, 12, 1, 8, 6, 4, 2, Oil Rate Water Cut.16.14.12.1.8.6.4.2. Water Cut B.H. Pressure (psia) 1, 2 BHP GOR 8, 16 6, 12 4, 8 2, 4 5 1 15 2 25 3 35 4 45 Days on Production GOR (MCF/STB) Figure 6 Well A-3 oil rate, water cut, bottom hole pressure and gas-oil ratio performance Figure 7 Well A-3 productivity index (PI) and drawdown pressure
SPE 9593 9 Figure 8 Effective oil permeability and Skin changes with time Figure 9 Progressive optimization of history match quality
1 SPE 9593 A-1 x A-6 8' MC538 MC582 Fault 1 Fault 2 x 6' 5' MC582#1 x A-3 Fault 3 ' 4' Figure 1 T4B net sand map with fault/facies boundaries for history matching Figure 11 Rock compaction porosity and permeability variation with net effective stress
SPE 9593 11 Measured History_Match_5 History_Match_7 Measured History_Match_5 History_Match_7 1 2.5 9 Bottom hole pressure (psia) 8 7 6 5 4 3 2 1 Gas-Oil Ratio (Mscf/stb) 2 1.5 1.5 5 1 15 2 25 3 35 4 45 Days on Production 5 1 15 2 25 3 35 4 45 Days on Production Figure 12 Bottom-hole pressure and gas-oil ratio history matches A-3 HM7 A-3 HM5 A-6 HM7 A-6 HM5 A-3 HM7 A-3 HM5 A-6 HM7 A-6 HM5 9 25 8 Cumulative Oil (MSTB) 7 6 5 4 3 2 Cumulative Gas (MMSCF) 2 15 1 5 1 25 5 75 1 125 15 Days on Production 25 5 75 1 125 15 Days on Production Figure 13 Prediction of cumulative oil and gas from two history matches