A comprehensive reservoir simulation study was recently carried out for the A4 reservoir located in the Niger Delta. The A4 reservoir is divided into two fault blocks (Main and West) that are connected in the down-dip part of the reservoir both in the oil leg and aquifer. Original Oil-Water Contact (OOWC) was logged in the reservoir, but no Original Gas-Oil Contact (OGOC) was logged by the wells that penetrated the reservoir. Thus, there existed uncertainty in the OGOC from the Highest Known Oil (HKO) to the crest of the reservoir.
During the period of the simulation project, two oil producers (A4-1p and A4-2p) were producing from the Main Block, while one water injector (A4-1i) was providing pressure support. Two additional oil producers were then being planned to increase the recovery from the reservoir. One of the wells was planned to be drilled up-dip of the existing two producers in the Main Block, while the other well was planned to drain the West Block.
Base model deterministic history-match and sensitivity studies were conducted to gain insight into the reservoir performance and parameters that affect history match, especially the OGOC. Then, probabilistic history-matching was carried out to assess the full range of uncertainties of the different history-match parameters with special consideration to the OGOC.
Probabilistic history-matching shows that the P10 OGOC for the Main Block is about 24ft shallower than the HKO, which was also supported by the base deterministic model. The simulation models were then used to forecast the performance of the two additional planned development wells to validate the planned landing depth of the completions. The two additional development wells were drilled and brought online. Initial test results from the new development wells were consistent with the pre-drill base deterministic simulation predictions.
Prediction of reservoir performance during water displacement process is a routine procedure for homogeneous reservoirs but complicated in heterogeneous reservoirs. The Stiles method has consequently been used over time in the industry for such reservoirs. This method, however, is evidently time consuming and tedious as the varying permeability values are reordered and lumped. This paper applies the Welge procedure to a stratified reservoir without reordering or lumping of permeability with the aim to ensure improved productivity by more proper planning, more efficient use of resources and determination of the economic viability of the project. This paper also seeks to formulate a procedure that can judiciously handle even larger sets of permeability values to produce more accurate result
A fractional flow equation was derived for any number of layers to generate a single fractional flow curve (FFC). Injection inflow into a layer was determined using the layer capacities and this facilitated calculation of times to breakthrough and times to attain a particular saturation after breakthrough. A formula was then derived to determine the oil produced at any instant. A software was designed for the entire procedure to ensure faster and more accurate predictions. Results showed that heterogeneities had no effect on the microscopic displacement and thus the fractional flow curve remained unchanged whether the reservoir was heterogeneous or not. Heterogeneities affected only the total flow in the distinct layers and thus times to attain specified average water saturations. The results of oil recovery obtained were compared to those obtained using the Stiles method to demonstrate that this method is faster without loss of accuracy.
Ogolo, Naomi Amoni (Institute of Petroleum Studies, University of Port Harcourt) | Iloke, Emeka (Department of Petroleum Engineering, University of Port Harcourt) | Godstime, Timothy G. (Department of Petroleum Engineering, University of Port Harcourt) | Onyekonwu, Mike O. (Department of Petroleum Engineering, University of Port Harcourt)
Water salinity is one primary factor that triggers migration of clayey fines in hydrocarbon reservoirs. However, the presence of some agents in the formation can delay this process and Aluminum oxide nanoparticles (Al2O3NP) have been proposed as one of such agents that can control fines migration. The primary objective of this study therefore is to experimentally determine the amount of fines free water effluent (in terms of pore volume) that can be produced from sand packs containing Al2O3 nanoparticles at different levels of water salinity. Another objective is to investigate the optimum sand treatment duration with Al2O3NP in control of fines migration.
The sand samples contained 5% clayey fines obtained from the Niger Delta and a constant flow rate of 3ml/min was maintained for all the experiments which were conducted under standard condition. The amount of Al2O3 nanoparticles used in the samples was 20% of the clay content, but Al2O3 NPs were not used in all the reference experiments. Two different sets of experiment were conducted in this work; the first set of experiment involved flowing various salinity levels of water ranging from 0 – 40g/l through sand packs while the second involved soaking sand in brine for various numbers of days before flowing brine of 5g/l salinity through the sand.
The experimental results showed that Al2O3 nanoparticles have the capacity to control clay mobilization in sands triggered by low water salinity. For the use of light crude at a salinity of 15g/l and 30g/l, about 25pore volumes and 33pore volumes of fines free effluents were produced respectively from the sand samples containing Al2O3 nanoparticles while about 13pore volumes and 21pore volumes of clean effluents were produced for the reference experiments respectively for a bulk volume of sand of about 55cm3. For the use of medium crude at a salinity of 15g/l and 30g/l, about 23pore volumes and 32pore volumes of fines free effluents were produced respectively from the sand samples containing Al2O3 nanoparticles while about 8pore volumes and 13pore volumes of clean effluents were produced for the reference experiments respectively. A comparison of the results of the sand samples containing Al2O3 nanoparticles with the reference results shows that the presence of Al2O3 nanoparticles in sands can control clay mobilization triggered by low water salinity. The results from the second part of the work showed that the maximum volume of clean effluent was recovered on the zero day of soaking. This implies that soaking is not required to achieve effective fines trapping in sand since the performance of fines trapping by Al2O3 NP diminishes with time.
Sand Production is one of the major challenges in oil and gas wells. It damages well head equipment and flowlines leading to lost production time and unnecessary workover expenses. Meanwhile, utilizing sand control measures when not needed can reduce production rates while reducing profits. Several methods have been developed to accurately predict sanding potentials. However, most are rather complex and time consuming. This study was justified to develop a real-time sanding model with minimal input parameters using well log data.
A geomechanical model was developed to estimate critical pressure below which sand production is expected. Effective stresses at a stable perforation cavity and far field were established using stress-strain relationship. Hoek Brown's failure criterion was applied to investigate the failure mechanics once stability was lost. The parameters in the model included poisson ratio v, uniaxial compressive strength C_o, biot's poroelastic coefficient α, overburden pressure P_ob, and Hoek Brown's material constant s and a. Five different hypothetical case studies were used to validate the model and the trends are very encouraging. A FORTRAN program was written for the model in order to facilitate sanding predictions.
The results observed by the model gives curves that increase at various points of depth, indicating potentially weak sandstone where sanding should be expected. A bottomhole flowing pressure, Pwf, 2500 psi was specified. It was observed that case A will not experience sand production. Cases B and C will experience sanding in the intervals 3000 - 3675ft and 3000 - 3625ft respectively. Cases D and E will experience sand production. Upon comparison with other published analytical models such as
This model serves as a useful tool for making well informed cost effective decisions regarding sanding and sand control requirements.
Nwabia, Francis (Centre of Excellence in Geosciences and Petroleum Engineering, University of Benin, Nigeria) | Osagie, Ehiosu (Centre of Excellence in Geosciences and Petroleum Engineering, University of Benin, Nigeria) | Eghobamien, Liberty (Centre of Excellence in Geosciences and Petroleum Engineering, University of Benin, Nigeria) | Nwonodi, Chike (Shell Petroleum Development Company, Port Harcourt) | Sonde, Adenike (Shell Petroleum Development Company, Port Harcourt) | Awa, Chukwunweike (Shell Petroleum Development Company, Port Harcourt)
FLO reservoir in the depth range of 8225-8780 ftss has an unknown nature of compartmentalization, unknown fluid property and also five well penetrations with none encountering OOWC (original oil water contact). Resolution of these uncertainties in this study created platform for the reservoir development in terms of growing production and increasing the reservoir ultimate recovery. This paper therefore focuses on an integrated approach of resolving uncertainties associated with key reservoir evaluation parameters to deliver a fit-for-purpose development plan of the reservoir.
A multidisciplinary approach, involving integration of: PVT (Pressure Volume Temperature) Property estimation, Fault Seal Analysis (FSA), Petrophysical analysis and Dynamic simulation were employed to pin down these uncertainties in fluid contact and connectivity across blocks K, L and M within FLO reservoir.
PVT property estimation was used to capture the phase behaviour of FLO reservoir fluids. While FSA, which relied on the degree of throw thickness and lithologic juxtaposition, was used to validate connectivity across fault blocks in FLO reservoir. Possible base case contact for the two producing blocks in the reservoir was established through dynamic reservoir model calibration by history matching for 41 years of production history.
Results obtained from FSA, pressure profiles, sand-to-sand juxtaposition and dynamic history matching all combined showed an established hydraulic communication between reservoirs block K & M and also blocks K & L. The dynamic history matching with adjustments within physical meaning of basic history matching parameters realized 8525 ftss and 8810 ftss for POWC (present oil water contact) of the reservoir blocks K and M respectively. With these uncertainties resolved, different tests of development concepts were conducted and checked for economic viability and this showed that a "Do Nothing" approach with recovery of 3.6 MMstb should be adopted for FLO K and a "New Well" with recovery of 1.92 MMstb be drilled to develop FLO M.
The deterministic analysis of cement sheath behavior under varying wellbore loads aids design and deployment of cement. Assurance of the ability of cement to achieve and retain zonal isolation is safety critical requirement for the successful drilling of a well and subsequent production operation. Exploitation of hydrocarbon resources in more challenging environments such as high pressure and high temperature (HPHT) intervals continues to push the frontier of cement design for zonal isolation purpose.
Severe temperature in HPHT environments has been known to result in degradation of cement over time. In addition to this risk of thermal degradation, the cement sheath is also subjected to varying pressure loads during well construction and production operations. The implication of the pressure load cycles is that mechanical properties of conventional cement recipe may not able to guarantee long term zonal isolation especially in HPHT wells with the high magnitude of pressure load variations. Proper understanding of the scale of the varying pressure loads in the wellbore and the corresponding stresses generated in the three components of the wellbore system (i.e. casing, cement and formation) is pivotal to designing a suit for purpose cement recipe that will eliminate loss of zonal isolation during the entire life span of a well.
Finite element analyses tools have been successfully used to gain knowledge of material behavior when subjected to varying stresses. In this project, investigation of the cement sheath behavior using finite element analysis was carried out to determine the mechanical properties of cement required to ensure retention of zonal isolation under continuously changing wellbore pressure loads during drilling and production phases of typical HPHT well in deltaic depositional environment. The analysis also aided drilling operation optimization in the ongoing HPHT campaign by Shell Petroleum Development Company in the Niger Delta.
Kilic, Cem (Shell Petroleum Development Company of Nigeria) | Das, Anindya (Shell Petroleum Development Company of Nigeria) | Ehighebolo, Thaddeus (Shell Petroleum Development Company of Nigeria) | Balogun, Tayo (Shell Petroleum Development Company of Nigeria) | Adenaiye, Olaniyi (Shell Petroleum Development Company of Nigeria) | Bhattacharya, Tirthankar (Shell Petroleum Development Company of Nigeria) | Jiang, Kun (Shell Petroleum Development Company of Nigeria)
Estimation of initial Hydrocarbon-Water-Contact in the light of conflicting information is critical to overall field development plan and project economics. Understanding the causes of conflicting information requires an integrated investigation of potential sources of the information and a structured approach for developing and ranking plausible explanations.
R11 reservoir in Yama field has conflicting information from two wells drilled 19 years apart, which indicates the possibility of compartmentalization within the reservoir or pressure depletion from a nearby field. The discovery well, which is closer to the crest, encountered a GDT and GWC is estimated to be at 9790 ftss with an assumed regional water gradient. A later appraisal well, located at the flank of the structure, clearly logged a GWC, but it is 126 ft. deeper than the estimated GWC from the discovery well. In addition, the appraisal well recorded 120 psi lower pressure than the discovery well. This conflicting information could be explained by 4 possible scenarios: 1) Errors in measurements, 2) Uncertainty in regional water gradient line 3) Reservoir compartmentalization 4) Pressure depletion from a nearby producing field.
While the vintage of tool for pressure and depth measurement in the discovery well is relatively old, the difference of 126 ft. due to measurement error is unlikely. All the pressure points align quite well and estimated depth measurements errors are much smaller. On the other hand, pressure analyses with a range uncertainty in regional water gradient could narrow the difference, but not all of it alone. Possibility of reservoir compartmentalization due to faulting has quite a large impact in overall field recovery and the reservoir development. The last possible explanation for the conflicting information is the potential depletion of the pressure from a nearby field via a connecting aquifer. Analyses indicate that while it is possible to lower the reservoir pressure due to production from a nearby field, the magnitude of the pressure-drop would have been significantly smaller.
Based on a series of static and dynamic modelling as well as sensitivity runs, the conflicting information can be explained by pressure depletion and the reservoir is in communication. This scenario is selected as the "Base Case" for development planning. On the other hand, the compartmentalized scenario is also considered a possibility but as a "Low Case" scenario, hence it is included in field development scenarios and the impact of it is built in the project economics.
The oil and gas production process is driven by technology. The impact technology plays in the process is such that the oil and gas industry ranks as one of the largest employers of PhDs and also one of the largest investors in Research and Development activities. These have resulted in the industry being also one of the industries with the largest number of expatriates. Countries with large oil and gas deposits have oftentimes relied on International Oil and Gas companies for the exploration of their deposits with the hope that the knowledge and technology will be transferred over time. This has not been the experience in a number of these countries and has caused them to develop deliberate programs and local content development policies to encourage and engage the local populace in the oil and gas production process. For the local content policies to be maximized, local companies must invest in research and development efforts to create value and develop relevant technology as this is the only way they can maximize the oil and gas related contracts. Investment in Research and development is a highly capital intensive and time consuming process and as such it is out of the reach of the local companies. This paper discusses the role of the academia in the development of technology and the local content. It also presents some strategies that can be deployed to engage the Nigerian Academia in the development of the local content in the oil and gas sector in Nigeria.
Awasthi, Amit (Shell Nigeria Exploration and Production Company) | Okonkwo, Arinze (Shell Nigeria Exploration and Production Company) | Afulukwe, Chuks (Shell Nigeria Exploration and Production Company) | Effiom, Oghogho (Shell Nigeria Exploration and Production Company)
Project B, consisted of five discrete subsurface elements; Remaining developed volumes, Infill opportunities, Resources in THIN-BED and Exploration prospects. These subsurface elements were at different levels of technical maturity and were planned into a single project maturity timeline with shared i(mpact on facilities. Based on level of technical maturity, two of the subsurface elements (THIN-BEDs, and Exploration prospects) were considered as requiring an appraisal plan to further mature their development options.
In anticipation of "lower for longer" oil price scenario, the appraisal strategy for the discrete elements was integrated and designed utilizing decision tree analysis. The appraisal strategy was developed for the immature subsurface elements, consisting of a variety of appraisal methods, each cost effectively geared towards fit for purpose data acquisition to mitigate the key uncertainties and enable further oil development in the field. Decision tree analysis for each of the immature subsurface elements, describing the possible outcomes with associated probability of success, was performed including fit for purpose economic analysis to understand & decide the value add and timing of appraisal.
This integrated appraisal strategy including decision tree analysis; provided the basis and strong logic to decide whether the appraisal is worthwhile and when is the most optimal time to do it.
This methodology demonstrates how the quality decision around field development planning could be made by using decision tree analysis to evaluate the value of the components, using associated uncertainty around estimated ultimate recovery. Furthermore, this analysis also is utilized to understand the timing of appraisal vis-a-vis the overall field/project development.
Nwosu, Obiora (tHE Shell Petroleum Development Company Nigeria Limited) | Olagunju, Adeyemi (tHE Shell Petroleum Development Company Nigeria Limited) | Agwuncha, Frank (tHE Shell Petroleum Development Company Nigeria Limited) | Odumodu, Somtochukwu (tHE Shell Petroleum Development Company Nigeria Limited) | Oghene, Nkonyeasua (tHE Shell Petroleum Development Company Nigeria Limited) | Ori-Jesu, Efeoghene (tHE Shell Petroleum Development Company Nigeria Limited)
The productivity of oil wells depends on a lot factors such as and not limited to environment of deposition, reservoir thickness, permeability, reservoir drive mechanism, drain hole length and formation damage at the near well bore region. The productivity of oil wells can also be linked to the effectiveness of the sand control method deployed in the well. Sand control methods play very important roles in safeguarding our assets, maximizing production from assets and reducing life-cycle OPEX for the well.
This paper presents a comparative approach towards understanding the effect of different sand control methods on productivity of wells completed in a mature reservoir in the Niger Delta. The methodology involves the use of statistical comparison of the production performance of 4 sand control methods installed in the XYZ reservoir in the YED field. The approach considers the productivity performance, the average sand reliability index, and the intervention frequency ratio.
The productivity performance of the completed conduits on XYZ reservoir shows that conduits completed with Slotted Liners showed impressive production performance as well as low sand production, while the wells completed with IGP had better production performance when compared to other sand exclusion methods. The drainage points completed with SCON showed average production performance, with high sand production averaging around 25-30 pptb for the completed conduits. The conduits that were completed with MCUGP showed below average production performance as well as high sand production.
The results in this work will help provide an easy guide to sand control selection as it concerns productivity in the Niger-Delta region. It will also deepen the understanding of the performance of different sand control methods in the Niger-Delta Region.