Volatile oil and gas condensate reservoirs were uncommon before 1930s. Since then they have been discovered with increasing frequency. This is attributed to the increasing drilling depths. Recently there has been a growing interest in these near critical fluids reservoirs. Large number of discoveries made it imperative to implement the relevant methods to deal with such reservoirs. Usual industrial practice in Pakistan is to use the P/Z plot to estimate the GIIP (Gas initially in place). This is the simplest method and does not require the set of PVT properties below the saturation pressure. However the P/Z method is limited in its application to only volumetric depletion type, dry gas, reservoirs. The general material balance equation gives reliable GIIP estimates, since it accounts for all drive mechanisms. Usually general material balance methods are not preferred in gas condensates, because these require standard PVT properties below the saturation pressure. These properties may be computed using Walsh-Towler algorithm, Whitson-Torp (K-value flash) method or Cubic Equation of State (EOS). This paper demonstrates the application of Walsh-Towler algorithm and K-value flash method (Whitson-Torp method) to calculate the standard PVT properties below the saturation pressure for a gas condensate reservoir. Then the application of Havlena-Odeh and Cole plot methods is exhibited to estimate the GIIP. The results are then compared with that of P/Z plot and an 11% over-prediction by P/Z plot was observed.
The E&P industry has been facing multitude of challenges including lack of large discoveries coupled with continuously declining production from existing assets. Moreover, the situation is aggravated due to large volumes of unproduced hydrocarbons at abandonment owing to unoptimized development strategies. This paper discusses the strategy adopted to revitalize declining production and target remainder of the sweet spots in a mature gas field on production for the last seven decades. Furthermore, the workflow introduced, integrates the surface and subsurface engineering strategies with an ideal blend of operational considerations that avoids heavy CAPEX involvement. The field presented in this paper has been producing since 1955, with around 112 wells in four independent reservoirs. Three of these reservoirs are fractured limestone with more than 80% depletion (with very little to moderate aquifer support). At its plateau, the field produced around 1,000 MMscfd gas. However, recently the production decline rose to around 7% annually, as the performance of multiple wells have gone down with declining reservoir pressure and water production. Therefore, to cut water production and arrest the annual field decline, various activities were carried out including cementing, tubing size optimizations, and chemical placements, but to no effect. Resultantly, a two-step workflow is developed that starts with selection of wells faced with rapidly declining production and high water-cut. These are then analyzed using production logging data for zonal contributions and contact movement. Next phase was to develop a comprehensive algorithm to analyze the re-processed seismic and geological parameters, integrated with reservoir simulation to identify the undrained area and quantify potential gain from the optimized sidetracks. Deploying the proposed approach yielded immediate returns in the form of initial gains of around 10 MMscfd gas production from the first two wells with addition of around 10-15 BCF reserves in the portfolio. Similarly, implementation of the strategy on another set of two wells resulted in production enhancement of 6 MMscfd gas and ~6BCF additional reserves from one of these wells. While the other well did not yield optimized results due to operational challenges which includes uncontrolled losses in complex and intricate fracture network. Consequently, this triggered the addition of fracture attribute study in the earlier developed workflow, further strengthening the sidetrack programs. While liquid loading and water breakthrough are common challenges pertaining mature assets, stereotyping one solution across the board may not result in optimum results. The proposed workflow delineates multiple factors for production gains including G&G analysis, well construction details, additional fracture-attribute study, and completion types, that can be adjusted to harvest the maximum rewards in such mature fields.
It's almost certain that the oil & gas industry has passed its plateau for large field discoveries. This places an extra burden on the efficient handling of our mature assets, as reasonable amount of hydrocarbon still exists in such reservoirs. However, the ever-increasing cost of new projects and low production gains hardly justify the economics. This study presents a novel approach applied on a mature gas giant, in order to revitalize old wells, optimize surface network and exploit the scattered sweet spots still prevailing in the field, with integrated surface and subsurface engineering strategies. The field under study has been producing since 1955, with around 112 wells, completed in four independent formations. The primary reservoir (Reservoir-A) is categorized as a depletion-drive gas reservoir and has been on production since the field's inception; the reservoir pressure has depleted from 1,900psi to 300psi. The other formations: Reservoir B, C & D started producing from 1968, 2000 and 2015 respectively. At its peak, the field produced ~1,000 MMscfd gas; but lately, the production decline rose to around 7-8% annually, mainly due to natural depletion. However, deterioration in well performances and limitations of surface facilities (feederlines, Gas-Gathering-Mains (GGMs) and compressors) have also exacerbated this decline, due to the additional pressure drops amassed in their flow dynamics with reservoir pressure depletion & water production. To counter the field's rapid production decline, a comprehensive workflow and an Integrated Asset model was developed, with an absolute focus on the NPV for each development. At the subsurface level, Reservoir-B (still under-developed) was the first targeted, as most of its wells were producing at uneconomical rates. An ant-tracking algorithm was run on the newly acquired 3D-seismic; and natural fractures - near the 02 high producers in Reservoir-B, were analyzed. A workflow was then developed to target similar fractures and the integrated impact, on surface facilities, was evaluated. Finally, three successful pilots were drilled in Reservoir-B and Reservoir-C, to evaluate the post-drill dynamics. Based on the real-time performances of these pilots with existing producers and surface facilities, the integrated field model was updated, coupling the wells, surface facilities and all four reservoirs (with independent reservoir models). As a result of this integrated model, 12 more wells, 09 workovers, 02 GGM optimizations and 03 compressor modification jobs were finalized; giving an overall increase in EUR by 800 BCF, while the NPV of the field increased by 131 MM$. This study offers an innovative approach that has been followed to utilize each data-set systematically, in order to re-vitalize a field even after 84% depletion. The paper also describes the evaluation process for all the optimization opportunities and their impact on the NPVs, to reap the maximum reward from such an old field.
It is well established that the oil & gas industry has long surpassed its plateau for large discoveries. Thus, many companies have shifted their focus to cost-constrained policies for hydrocarbon discovery, making it difficult to have a strong sub-surface definition. Add the structural uncertainties and complexities of new discoveries in this scenario, the optimized field development becomes a real challenge. This study presents the development strategy established for a reservoir, with low seismic resolution, using the integrated dynamic data to define the reservoir structure and optimize its recovery. This paper focuses on a relatively new discovered formation in one of the oldest gas giants in Pakistan. The productive sandstone units are in beds with thicknesses ranging from 10-50m, separated by mudstone intervals. The low seismic resolution has posed a major challenge in finding the sweet spots for hydrocarbons above Gas-Water-Contact (GWC)-resulting in 60% well failures. Therefore, a workflow was developed to analyze various dynamic datasets in conjunction with the re-interpretation of seismic to delineate the reservoir structure. This included re-interpretation of MDT data and formation gradients, core re-evaluation, critical analysis of reservoir pressure variation, well failure analysis, thickness maps and PVT properties. The first four wells drilled in this reservoir had two successes, both in the Western compartment. However, sudden water production loaded up these wells only after 123 BCF production, which was a lower recovery as compared to GIIP estimates. After further geological evaluation and 3D seismic re-acquisition, more wells were drilled – revealing another deposition with a different GWC, but only 1 well was successfully completed as a producer, adding around 38% more reserve, while the others were again unsuccessful due to high structural uncertainty. This led to the development of a detailed algorithm for integrating dynamic data set with seismic re-interpretation and thickness mapping with the help of which two more wells were drilled and added around 22 % more reserves to the current mix. The dynamic data of these wells have now been further evaluated which revealed that the two compartments are in fact in communication with each other despite having a 60m difference in their GWCs. Finally, two more wells are now planned which will add around 10-20 % more recoverable volumes, giving an overall EUR of ~80% from these compartments. The main achievement of this workflow is a robust algorithm to integrate the dynamic data with geological interpretation to delineate a low-resolution reservoir since the seismic interpretation cannot be solely relied upon for developing such reservoirs. The paper also illustrates the robust engineering models and data analyses in a more systematic manner to ensure optimum locations for future wells to access, the otherwise, undrained locations.
It's almost certain that the oil & gas industry has passed its plateau for large field discoveries. This places an extra burden on the efficient handling of our mature assets, as reasonable amount of hydrocarbons still exist in such reservoirs. However, the ever-increasing cost of new projects and low production gains hardly justify the economics. This study presents a novel approach applied on a mature gas giant, in order to revitalize old wells, optimize surface network and exploit the scattered sweet spots still prevailing in the field, with integrated surface and subsurface engineering strategies. The field under study has been producing since 1955, with around 112 wells, completed in four independent formations. The primary reservoir (Reservoir-A) is categorized as a depletion-drive gas reservoir and has been on production since the field's inception; the reservoir pressure has depleted from 1,900psi to 300psi. The other formations: Reservoir B, C & D started producing from 1968, 2000 and 2015 respectively. At its peak, the field produced ∼1,000 MMScfd gas; but lately, the production decline rose to around 7-8% annually, mainly due to natural depletion. However, deterioration in well performances and limitations of surface facilities (feederlines, Gas-Gathering-Mains (GGMs) and compressors) have also exacerbated this decline, due to the additional pressure drops amassed in their dynamics with reservoir pressure depletion & water production. To counter the field's rapid decline, a comprehensive workflow and an Integrated Asset model was developed, with an absolute focus on the NPV for each development. At the subsurface level, Reservoir-B (still under-developed) was the first targeted, as most of its wells were producing at uneconomical rates. An ant-tracking algorithm was run on the newly acquired 3D-seismic; and natural fractures - near the 02 high producers in Reservoir-B, were analyzed. A workflow was then developed to target similar fractures and the integrated impact, on surface facilities, was evaluated. Finally, three successful pilots were drilled in Reservoir-B and Reservoir-C, to evaluate the post-drill dynamics. Based on the real-time performances of these pilots with existing producers and surface facilities, the integrated field model was updated, coupling the wells, surface facilities and all four reservoirs (with independent reservoir models). As a result of this integrated model, 12 more wells, 09 workovers, 02 GGM optimizations and 03 compressor modification jobs were finalized; giving an overall increase in EUR by 800 BCF, while the NPV of the field increased by 131 $MM. This study offers an innovative approach that has been followed to utilize each data-set systematically, in order to re-vitalize a field even after 84% depletion. The paper also describes the evaluation process for all the optimization opportunities and their impact on the NPVs, to reap the maximum reward from such an old field.
In the midst of current oil prices, most companies have shifted their focus on cost-constrained policies for hydrocarbon exploitation, thereby making robust subsurface description a real challenge. Developing a reservoir in such scenario is a massive problem. This study presents various engineering algorithms on such a low-resolution and uneven sandstone reservoir, to optimize the development and expected ultimate recovery - while honoring multiple challenges and limitations. This study focuses on a newly discovered formation, in one of the oldest fields in Pakistan. The productive section of the reservoir comprises of sandstone units in beds up to 40 m thick, separated by mudstone intervals; and is interpreted to be deposited in lower progradational intervals of a delta. To date, three different depositions have been identified with two of them in hydraulic communication and one isolated with faults. Since the seismic data has limitations in its resolution; various engineering analyses were carried out, among which the variations in reservoir pressures, GWC and PVT properties played a major role in the identification of partially drained and isolated prospects. The first two successful wells in the isolated compartment were high producers. However, sudden water production (from fractures) loaded up these wells with only 45% recovery from the compartment - very low for a weak-water drive dry gas system. The static and dynamic data set also showed the existence of more Hydrocarbons. Thus, several engineering and geological information, including the re-interpreted Seismic and simulation models, were applied to analyze the possibilities of concurrent sweet spots. Finally, after utilizing multiple algorithms & risk calculations, more wells were drilled - leading to the revelations of two more depositions in the reservoir, which were in hydraulic communication with each other but isolated with the first compartment. This added around 60% more reserves to the current mix of resources. Two more wells are now planned in the reservoir to optimize the field potential in both compartments. This will lead to an additional 23% reserves value, giving an overall EUR of ~83% from these compartments. The main achievement of this study includes the exploitation strategy of a complicated depositional system to optimize a reservoir full of uncertainties. Since the seismic cannot be solely relied upon in such formations; this paper also illustrates the robust engineering models and detailed algorithms to ensure the development of such low-resolution reservoir without incurring major costs. This study offers an innovative approach that can be undertaken to place the wells at optimum locations, along with the utilization of each data set in a more systematic manner to access the, otherwise, undrained locations.
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