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Pressure transient analysis has been extensively applied to detect anomalies in a reservoir system. These anomalies may be presented in the form of an intersection of the crestal and the antithetic fault associated with a growth fault. Interpretation of this fault can only be achieved through the use of pressure transient analysis. The objective of the research work is to analyze and test the faulted crest, depth of the anticline structure and examine the near well bore conditions in order to evaluate whether the well productivity is governed by wellbore effects (skin effects + well bore effect) or the reservoir at large. A case study of a well in the Niger delta is considered with a series of build up test carried out in two intervals of both upper and lower gauge readings. In this study, a computer aided design which uses a pressure derivative approach is used in this work to match the pressure derivative of an intersecting fault (angle) model to the field data, and the model assumes the characteristics of the reservoir. Based on the result of the interpreted data, simulation is done by using a non linear regression method (least square). The simulated data interpreted are achieved through the regression coefficient which provides a quantitative measure of the agreement between field data and the model. In conclusion, the best cases are taken from all the results and a nodal analysis is performed to diagnose the inflow performance of the well through the transient analysis in order to optimize the recovery of the oilfield.

Many hydrocarbon bearing formations in the Niger Delta are faulted, as reported by [

1) Test the faulted crest and depth of the anticline structure between the KRAKAMA east wells and the CAWTHORNE channel field.

2) Examine the near well bore conditions in order to evaluate whether the well productivity is governed by wellbore effects (skin + storage) or the reservoir at large.

3) Evaluate the well condition and reservoir characterization.

4) Provide an understanding of reservoir environment and the control which the geological architect exerts on fluid flow regimes and patterns.

5) Obtain the reservoir parameters for reservoir description such as reservoir conductivity (KH), productivity index (PI), flow efficiency, damaged ratio, skin factor (S), average reservoir pressure.

6) Monitor changes in average reservoir pressure so that we can refine our forecast of future reservoir performance.

7) Give a comprehensive interpretation of the acquired data for efficient reservoir development and management decisions.

The geology of the formation is shown in

Reservoir and Fluid data | |
---|---|

Bubble point pressure | 3883 psig |

GOR | 1032 scf/stb |

Oil FVF | 1.46 rb/stb |

Reservoir temperature | 172˚f |

Reservoir pressure | 4000 psia |

Oil SG | 0.8429 |

Gas SG | 0.65 |

Net oil sand volume | 0 |

Porosity | 0.24 |

Connate water saturation | 0.35 |

Average net thickness | 130 ft |

Wellbore radius | 0.3 ft |

Cumulative oil produced | 202 stb/day |

Tested oil rate | |

Production data | 20 |

Choke size | 20/64 in |

Net oil rate | 252.8 bbl/day |

Water cut | 43.85 |

GLR | 0.8 |

Wellhead pressure | 29.9 BarG |

1) Reservoir data (well data, production history, pvt)

2) KAPPA (petroleum exploration software which covers the pressure transient analysis).

3) Emeraude (production logging interpretation tools)

4) Topaze (production analysis tools and used to know the productive depth level)

5) Saphir (well test interpretation package).

The seismic study is carried out in the three wells to determine the level of faults boundary of the reservoir and the productive levels. This is done by using tool such as Topaze production tools.

Once the reservoir model is identified, it is necessary to compute the model parameters. The parameters estimated from the specialized flow regimes analysis, interdisciplinary input or both resources, simulation for the transient responses are computed. The initial simulated and the observed response usually differs. Modern analysis however is assisted by the nonlinear regression routines that automatically refine the parameter estimates until the simulation coincides with the observed data for the essential portions of the transient response.

Parameter | Min - Max (Value) |
---|---|

Confidence interval | 0.0197 - 0.0198 (0.0197) |

Correlation coefficient | 0.0391 - 0.157 (0.0783) |

Alpha | 0.316 - 0.752 (0.438) |

Skin | 0.0124 - 0.0284 (0.0204) |

K | 0.0473 - 0.0473 (0.0473) |

L_{1} (length) | 749 - 300 (1500) |

L_{2} (length) | 749 - 300 (1500) |

Angle | 44.929 - 179.716 (89.858) |

The QA/QC control panels include all the facilities linked to well test data acquisition and quality control. The QA/QC section consists of series of plot of different types (pressure gauges, the difference of the plot, the linear derivative of the plot). Tide analyses are also performed on the pressure data to remove the effect of pressure measurement which heavily influences the derivative behavior and errors in the analysis are frequent induced. It is important to remove these effects without removing the true reservoir response before attempting and interpretation. This is done by using a smoothing of 0.1 to reduce the noise derivative as shows in

The reservoir fluid properties are matched with PVT correlation in the model to calculate accurate viscosity and total compressibility of the fluid based on the assumed formation compressibility as shown in

Permanent downhole gauges are used to record the bottom hole pressure and temperature with time. The upper and lower gauges of the downhole tool record the readings at both static and flowing conditions of the well. The static and flowing gradient reading are also recorded to determine slope of the fluid gradient for fluid contact. Comparing the conditions of the test for both upper and lower gauge responses, Kappa-saphir software is used in the diagnosis and further result and interpretation of the analysis are discussed as follows.

Figures 10-12 show the gradient plot for the upper gauge, pressure derivative of the upper gauge and semilog of the lower gauge, whereas

Figures 13-15 show the Horner’s plot of the lower gauge, pressure derivative of the lower gauge and semilog of the lower gauge used in the analysis. However, Tables 6-8 show the result summary of different test analyses of the Horner plot as shown in the figures.

Figures 16-18 show the Horner plot of the upper gauge, semilog of the lower gauge and comparison of the gauge result.

Comparison of the gauge result

First radial test design build up | |
---|---|

Slope | −293.4 mD |

intercept | 2906.82 Psia |

second radial test design build up | |

Slope | 280.771 mD |

Intercept | 3542.49 Psia |

K (permeability) | 7.29 mD |

K (permeability) | 2.43 mD |

Skin | 17.9 |

Net ratio | 3.98 |

Intersection X | 0.9129 |

Distance | 734 |

Semi log line (Test Design build-up) | |
---|---|

Time from | 6314.54 h |

To | 33635 h |

intercept | 2967.22 Psia |

P @1hr | 1000.009 Psia |

Flowrate | 202 |

Pressure (p@0) | 3650 Psia |

Pws | 0.00564 Psia |

Permeability (k) | 25.5 mD |

Skin | 1.44 |

Semi log line (test design build-up) | |
---|---|

Time from | 138.90 h |

To | 33290.1 h |

Slope | 945.281 Psi |

intercept | 3031 Psia |

P @1hr | −361.834 Psia |

Flowrate | 202 Stb/d |

Pressure (p@0) | 2838 Psia |

Pws | 0.00564 Psia |

Permeability (k) | 0.168 mD |

Skin | 4.63 |

First radial test design build up | |
---|---|

Slope | 338.354 mD |

Intercept | 3098.05 Psia |

Second radial test design build up | |

Slope | −945 mD |

Intercept | 3471.48 Psia |

Kh | 60.6 m/ft |

K (permeability) | 1463 Md |

Skin | 11.8 |

Net ratio | 2.49 |

Intersection X | 0.81831 |

Distance | 370 ft |

Result | |
---|---|

Tmatch | 0.18300 h |

Pmatch | 3.8 × 10^{−4} psia |

Delta p | 202 Stb/d |

p@d=0 | −22,300 psia |

Production index | 0.00781037 Stb/d |

compressibility | 0.02590 psi |

Alpha | 1 |

Skin | 3.24 |

Delta P skin | 8448.18 psi |

Semi log line (Test Design build-up) | |
---|---|

Time from | 7751.54 h |

To | 4530.70 h |

Slope | 3143.06 psi |

intercept | 3611.12 psia |

P @1hr | −7660.31 psia |

flowrate | 202 Stb/d |

Pressure (p@0) | 22,300 psia |

Kh | 6.43 mD/ft |

Permeability (k) | 0.0493 mD |

Skin | 24 |

First radial test design build up | |
---|---|

Slope | −1059.19 mD |

Intercept | 3677.74 psia |

Second radial test design build up | |

Slope | −2759.17 mD |

Intercept | 5823.45 psia |

Kh | 19.2 m/ft |

K (permeability) | 0.148 mD |

Skin | 28.1 |

Net ratio | 2.6 |

Intersection X | 0.796582 |

Distance | 281 ft |

Semi log line (Test Design build-up) | |
---|---|

Time from | 5220.58 h |

To | 6975 h |

Slope | 1967.38 psi |

Intercept | 3608.1 psia |

P @1hr | −2618.24 psia |
---|---|

Flowrate | 202 Stb/d |

Pressure (p@0) | 54800 psia |

Kh | 10.2 md/ft |

Permeability (k) | 4.0708 mD |

Skin | 3.38 |

One of the main objectives of the research work is to estimate whether the productivity is governed by skin + storage, but as seen from the model result, the productivity is governed by skin + storage and its value predicting a low productivity index 0.03025 STB/D)/psi with a skin effect of 0.014. The result of the skin shows positive causing an increase in the pressure drop along the wellbore as shown in

The second stage is the spherical flow regime which is attributed as a result of the effect of partial penetration of the fluid as fluid flows spherically from the formation into the wellbore before the top and bottom boundaries are reached. The reservoir thickness of the formation is calculated from the well-log survey as 130 ft but only 20 ft of the total formation is perforated. From the plot, the spherical flow (half slope) is used to calculate the ratio of vertical to radial permeability given as 0.00446. The spherical flow lasts for about one cycle (10 - 100 hrs).

The third stage of the flow regime is the transient state (infinite acting radial flow). IARF is reached after the wellbore effect becomes negligible, the effect of well geometrics, the heterogeneities are passed and the lateral boundaries are detected. From the plot, the transient period begins at 100 hrs and ends at 1000 hrs and the permeability estimated in this period is given as 0.684 md, which is a very low permeability. This period only lasts for a complete cycle before the transition of the transient into the pseudo steady state. This is due to the effect of the boundary as pressure drops with time are constant and the flow regime is linear to the wellbore.

From the Horner plot shown in

Pressure derivative plot of the lower gauge reading shows the flow regimes of the fluid and their pressure response with time is shown in

The productivity index is estimated at 0.034 (STB/D)/psi and a negative skin effect is also estimated (−0.00487), which indicates well improvement i.e. there is no pressure drop due to skin effect around the wellbore. The second stage of the flow regime is the transient state (infinite acting radial flow). From the plot in

The fifth flow regime is a spherical flow. This flow regime shows the effect of fluid flow due to the effect of the intersecting fault boundary cutting across an anticlinal structure. From the plot an estimate of the ratio of the vertical to radial permeability is done to account for the vertical flow across the barriers (boundaries), the estimated value is 0.075. The sixth flow regime is the linear flow. The geometry of a linear flow streamline consists strictly of a parallel flow vectors. The presence of a second fault intersecting the sealing fault as seen in

The seventh flow regime depicts the intersecting angle of the boundary. The Horner plot is used to validate the test model of the sand. From the Horner plot shown in Figures 15-17, the first radial slope is more than double of the second radial flow which is due to the presence of faults.

In

Based on these results, a complete system analysis can be done to determine the optimum measure taken to optimize the total recovery of the reservoir sand and also help to determine the cost effectiveness of treatments under consideration and assists in completion decisions. This thorough evaluation of the complete producing system establishes the flow rate versus pressure drop relation for each component of the producing system. These could be as a result of the barriers from the interpretation of the gamma ray log of the formation as the matrix stimulation in 1995 was carried on the formation to improve its productivity and there was no positive result of improvement.

Barrier bar sands are deposited in a marginal marine environment on top of the finer grained barrier foot deposits. In a barrier bar, clay breaks are correlated over a long distance. The continuity of clay breaks or other barriers can be predicted from the depositional environment. The clay breaks may limit or stop the vertical flow of the fluids.

A carefully study is needed for the behavior of reservoirs and establishing the fact that wellbore effect and skin contributes to low production of hydrocarbon as a result of intersecting fault boundary.

We thank the management of SPDC for giving me data to carry out the research.

The authors declare no conflicts of interest regarding the publication of this paper.

Ihekoronye, K.K. and Nwosu, I.P. (2019) Pressure Transient Analysis of an Intersecting Rollover Faulted Crest Boundary in Niger Delta Oil Field. Open Journal of Yangtze Gas and Oil, 4, 125-143. https://doi.org/10.4236/ojogas.2019.42010