Reservoir Modeling & Simulation

Reservoir Simulation Modelling: Do you think it is easy to convert an Eclipse data deck into Petrel project? It is literally a couple of clicks but you need to be reminded that QCing converted Petrel case can be tedious. I attached a mindmap which I developed while ago to guide you through main steps for a proper converted Petrel case. You may need to download some Schlumberger Intouch Solutions by contacting them if you need more info.

Tunu is a mature giant gas field, located in swamp area of Mahakam delta. It covers an area of 75 km long and 15 km wide with enormous multi-layer sand-shale series deposited within a deltaic environment. The production commenced in 1990 and peaked in 1999 (1.5 Bcfd yearly average), with current production around 600 MMscfd, and nearly 1,200 wells drilled from 34 platforms. As the field is entering into the late stage of its life and number of new wells being drilled is decreasing, the field potential is now quite dependent on the existing perforation portfolio. Owing to the significant number of wells, with multi-layer reservoirs encountered by each well, the perforation portfolio needs to be managed in an efficient and detailed manner. An intensive well review has been performed, involving more than 9,000 reservoirs located in over 800 active wells. It commenced with an evaluation of perforation gain and its associated risks at reservoir level, which are then progressively summarized into higher levels; well, platform, and field. Perforation sequences are then defined for each well following a bottom-up perforation strategy while also adapting the risks of each reservoir. Ultimately, an organized reservoir chart is constructed where we can dynamically surveil the field perforation portfolio. Results of this intensive well review have enabled the shift of production forecast methodology from statistical toward deterministic approach. In the new approach, for instance, perforation sequences and time interval between the sequences in each well are deterministically determined on a well by well basis according to the aforementioned reservoir chart. Compared to the previous methodology, this new approach yields a better representation of the actual operations. Another area benefited by the results of the intensive well review is the optimization of well intervention planning. The identified workload is grouped together based on the remaining perforation portfolio of each platform while also respecting their location to define several well intervention clusters. Implementation of this clustering system optimizes perforation planning which reduces the time spent by perforation barges to travel from one platform to another, thus allowing more time for perforation.

A numerical model is simulated for well testing. The single phased horizontal well is modelled using a light oil simulator. The near wellbore region is accurately modelled using Tartan grids. Millions of grid blocks around the well capture the transients and the radial flow into the wellbore in a very tight reservoir and reflects the characteristic behaviour of horizontal wells in low permeability formations. The drawdown solution is used to validate the horizontal well model. Sensitivity analysis carried out under pseudo-steady state conditions investigates the effect of permeability and horizontal well length on the rate of oil well production under three scenarios. Results show that of the two properties, permeability had the most sensitized effect on the rate of oil well production

Formation damage is a major problem experienced in the operation and development of petroleum reservoir. Its occurrence, occasioned with the release of particles, water, emulsions or scales, hitherto impairs the hydrocarbon delivery/transport system. Formation or skin damage impedes flow of fluids into the wellbore and cause low permeability, hence reducing the productivity of the wells. The production loss directly reflects the economic loss due to formation damage. In the extreme, damage may cause the Well to be uneconomic and be shut-in. The objectives of this project was to determine Stimulation C andidate for three (3) Wells in the Niger Delta Oilfield, using the R ratios, stimulate the candidate wells and make comparison between the wells with regard to the Pre-Stimulation

Reservoir water level (RWL) prediction has become a challenging task due to spatio-temporal changes in climatic conditions and complicated physical process. The Red Hills Reservoir (RHR) is an important source of drinking and irrigation water supply in Thiruvallur district, Tamil Nadu, India, also expected to be converted into the other productive services in the future. However, climate change in the region is expected to have consequences over the RHR’s future prospects. As a result, accurate and reliable prediction of the RWL is crucial to develop an appropriate water release mechanism of RHR to satisfy the population’s water demand. In the current study, time series modelling technique was adopted for the RWL prediction in RHR using Box–Jenkins autoregressive seasonal autoregressive integrated moving average (SARIMA) and artificial neural network (ANN) hybrid models. In this research, the SARIMA model was obtained as SARIMA (0, 0, 1) (0, 3, 2)12 but the residual of the SARIMA model could not meet the autocorrelation requirement of the modelling approach. In order to overcome this weakness of the SARIMA model, a new SARIMA–ANN hybrid time series model was developed and demonstrated in this study. The average monthly RWL data from January 2004 to November 2020 was used for developing and testing the models. Several model assessment criteria were used to evaluate the performance of each model. The findings showed that the SARIMA–ANN hybrid model outperformed the remaining models considering all performance criteria for reservoir RWL prediction. Thus, this study conclusively proves that the SARIMA–ANN hybrid model could be a viable option for the accurate prediction of reservoir water level.

Formation damage is a major problem experienced in the operation and development of petroleum reservoir. Its occurrence, occasioned with the release of particles, water, emulsions or scales, hitherto impairs the hydrocarbon delivery/transport system. Formation or skin damage impedes flow of fluids into the wellbore and cause low permeability, hence reducing the productivity of the wells. The production loss directly reflects the economic loss due to formation damage. In the extreme, damage may cause the Well to be uneconomic and be shut-in. The objectives of this project was to determine Stimulation Candidate for three (3) Wells in the Niger Delta Oilfield, using the R ratios, stimulate the candidate wells and make comparison between the wells with regard to the Pre-Stimulation and Post-Stimulation analysis. An analytical method was used to calculate Productivity Index, PI; Permeability, K; Skin, S; Production Rate, q, R-Ratio and Pressure Drawdown, ΔP using data from Pressure build...

Over the last decade, there have been several discoveries of very significant oil accumulations in deepwater reservoirs. With advances in research and the availability of high-resolution seismic data, their variability and complexity have been well documented. For hydrocarbon exploitation purposes, however, the industry has been lacking an integrated approach to interpret these reservoirs using multiple domains and data efficiently consumed. This paper describes a series of innovative interrelated techniques, plus our observations to improve understanding of these types of reservoir at three scales:

Basin scale: Stratigraphic forward modeling is a useful method to simulate regional geological processes. Using this technique a paleo-basin floor surface reconstructed from seismic can be used to set a series of simulations. By varying several parameters, such as water level and water/sediments coefficients, within a reasonable range of values and comparing results to observed data plausible models are created. These, considered jointly, provide a picture of the uncertainty of the occurrence of observed features and sediment properties.

Sequence scale: Sinuosity and stacking configurations are critical factors that control local channel-fill patterns. By using seismic sections along channels, coupled with seismic reconstruction complex paleo-sequence geometries can be resolved. In our case a low-sinuosity channel was identified and a backstepping-fill pattern defined.

Reservoir scale: The quantification of net-to-gross is critical in exploitation. By using training grids and multipoint statistics methods a comprehensive facies model can be built. Training grids based on -fill patterns and channel geometry, are combined with probability properties to condition the overall stochastic distribution of facies. Additionally, uncertainties associated with this process are captured in an uncertainty workflow. Integrating these three techniques leads to a better understanding of reservoir-critical factors. The above approach is proven by using a seismic dataset from Campos Basin, Brazil, which contains well-documented reservoirs originallydeposited in a deepwater setting

Most giant clastic reservoirs in Iraq will need to apply enhanced oil recovery in the near future, as these reservoirs go to maturity. The need to develop a rapid and cheap assessment of the enhanced oil recovery methods has become a hot topic in petroleum engineering. Different field-scale heterogeneous geological models were built based on the Nahr Umr reservoir in the Subba oilfield to perform compositional reservoir simulations. The BoxeBehnken experimental design was employed to build and verify the proxy assessment model of miscible CO 2-WAG flooding. Four operational parameters of the miscible CO 2-WAG process were considered, including CO 2 slug size, ratio of CO 2 slug size to water slug size, cyclic length and bottom hole pressure. Using the proxy model, significant first order interactions were sorted out and different operating parameter interactions were established and analyzed for the evaluation of the miscible CO 2-WAG process. In similar oil reservoirs with similar geological conditions and fluid properties to the Nahr Umr reservoir, the proxy model can be applied to roughly predict the incremental oil recovery over the miscible CO 2-WAG flooding process at different levels of operating parameters. The approach could serve as screening criteria and a guide for the application of CO 2-WAG projects.

The reduction from three- to two-dimensional analysis of the permeability of a fractured rock mass introduces errors in both the magnitude and direction of principal permeabilities. This error is numerically quantified for porous rock by comparing the equivalent permeability of three-dimensional fracture networks with the values computed on arbitrarily extracted planar trace maps. A method to compute the full permeability tensor of three-dimensional discrete fracture and matrix models is described. The method is based on the element-wise averaging of pressure and flux, obtained from
a finite element solution to the Laplace problem, and is validated against analytical expressions for periodic anisotropic porous media. For isotropic networks of power law size-distributed fractures with length-correlated aperture, two-dimensional cut planes are shown to underestimate the magnitude
of permeability by up to 3 orders of magnitude near the percolation threshold, approaching an average factor of deviation of 3 with increasing fracture density. At low-fracture densities, percolation may
occur in three dimensions but not in any of the two-dimensional cut planes. Anisotropy of the equivalent permeability tensor varies accordingly and is more pronounced in two-dimensional extractions. These results confirm that two-dimensional analysis cannot be directly used as an approximation of three-dimensional equivalent permeability. However, an alternative expression of the excluded area relates trace map fracture density to an equivalent three-dimensional fracture density, yielding comparable minimum and maximum permeability. This formulation can be used to approximate three-dimensional flow properties in cases where only two-dimensional analysis is available.

Formation damage is a major problem experienced in the operation and development of petroleum reservoir. Its occurrence, occasioned with the release of particles, water, emulsions or scales, hitherto impairs the hydrocarbon delivery/transport system. Formation or skin damage impedes flow of fluids into the wellbore and cause low permeability, hence reducing the productivity of the wells. The production loss directly reflects the economic loss due to formation damage. In the extreme, damage may cause the Well to be uneconomic and be shut-in. The objectives of this project was to determine Stimulation Candidate for three (3) Wells in the Niger Delta Oilfield, using the R ratios, stimulate the candidate wells and make comparison between the wells with regard to the Pre-Stimulation and Post-Stimulation analysis. An analytical method was used to calculate Productivity Index, PI; Permeability, K; Skin, S; Production Rate, q, R-Ratio and Pressure Drawdown, ΔP using data from Pressure build...

Numerous studies carried out on Formation damage, but fewer investigations were conducted for the ideal diagnosis workflow. More understanding of geology, reservoir characteristics, and production data is essential to define the source, causes, and suitable treatment technique of formation damage for each well. In this paper, a workflow for the formation damage diagnosis is introduced to find location, potential source even natural or induced damage, root causes and recommend a suitable treatment method of the formation damage. The suggested workflow depends on vital steps including (1) planning and organizing the delivered data for solving the investigated problem, (2) collecting and analyzing all available data, (3) integration of the all geological, reservoir and production data, in addition the suggested workflow was applied on Hammam Faraun reservoir in El-Morgan oil field. In this reservoir, an integration of the available geological, reservoir, and production data was performed to make confident prognosis or diagnoses of formation damage and achieve a complete vision of the sources of formation damage and suggest solutions and treatments. Therefore, in assessing formation damage in the studied well, all aspects of the well and its history were integrated in this study, including: core analysis, XRD, mineralogy, water chemistry, reservoir geology, offset well production, reservoir fluids, production history, drilling fluids, cementing program, completion, stimulation and workover history, perforation reports. The diagnosis of the formation damage problem revealed that the suggested workflow was effective and can help diagnose formation damage problems in the entire oil and gas wells. The integration of geological, reservoir , production data led to accurate analysis, two sources of damage could be responsible for the damage in the studied well based on the geological and engineering data analysis and integration. Firstly, low quality water, secondly the using of an inappropriate stimulation fluid and sensitive formation minerals to fluids, and finally treatment with proper additives is highly recommended.

More than 40 small water dams and five plus cisterns have been built across the northern half of the High Mountains of Sinai Peninsula and its northern perimeter–out of focus–until May 2015 CE. The unprecedented mass construction of similar water dams was initially triggered by a Trustee in late 2000s CE, and later adopted by government institutions in late 2014 CE. It is driven by rural household need to secure more water for mountainous orchard agriculture, grazing and/or household consumption purposes during the dry periods. In practice, the construction approach is orchard-focused, not, integrated watershed management and/or ecological and agricultural zone-focused. It is a semi-arid landscape, dotted by 632 mountainous orchards (60 mm/year, sporadic ‘October-May’; orographic snow precipitation: 300 mm/year; evaporation rate 4,071 mm/year). The landscape is characterised by local networks of terraced wadis/fields, water dams, traditional irrigation channels (open conduits), plastered pools and water wells. On the other hand, Val Venosta/Vinschgau (in addition to the adjacent regions), all hold an extended 600km network of traditional irrigation channels (including the piping replacements). This network is mostly still in-use to supply the remote meadows with water, compared to the abandoned Sinaitic one. Hence, the dry Val Venosta/Vinschgau has the representative inner-alpine open air laboratory of Val Mazia/Matsch Tal (mean annual precipitation ‘rain-fall/snow’: 525 mm/year, 40 and 12 %, summer and winter respectively; evaporation rate: 180 mm/year ‘July-August’), contrary to the Sinai’s case. The adjacent vicinity of Val Mazia/Matsch Tal involves a potential network of irrigation channels and water reservoirs (change in water rights and distribution), and land-use patterns, where a low cost model could be conducted, towards the socio-ecological understanding and development of similar global mountain irrigation networks in practice.