The objective of matrix acidizing treatments is to remove the skin damage from the vicinity around the wellbore and enhance the permeability and the well productivity. While this is accomplished in sandstone by using reactive fluids to dissolve the clay and the surrounding cementing materials, carbonate stimulation is successful when the reactive fluids bypass the damage by creating conductive channels or "wormholes". It is rare in both treatments that the acids are used alone without several additives. The presence of any of these additives, which is required to achieve a certain function, may impact significantly the outcome of the acid treatment either positively or negatively. The objective of this study is to examine the effect of the type and concentration of several additives, which are currently in-use in the oilfield, on the calcite dissolution rate with HCl using the rotating disk reactor. Additives such as corrosion inhibitors, synthetic polymers, mono and divalent chloride salts, mutual solvent, dissolved iron, viscoelastic surfactants, and chelating agents were investigated.
The results showed that more reliable data was obtained at lower acid concentrations. Higher acid concentrations were associated with significant surface changes and inevitable source of error. The effect of corrosions inhibitors was studied by investigating three corrosion inhibitors (CI-A, CI-B, and CI-C) obtained from three different service companies. The presence of two corrosions inhibitors was associated with a reduction in the dissolution rate (between 7 and 45%), while the presence of the third one (containing formic acid) increased the rate of dissolution up to 38%. The effect of all other additives was further examined in the presence of one of the corrosion inhibitors. The presence of a synthetic polyacrylamide polymer significantly reduced the reaction rate down to 96% compared to a blank acid solution that did not contain the polymer.
Monovalent ions (sodium and potassium) showed little effect on the calcite dissolution rate, the presence of divalent ions such as magnesium chloride was associated with a reduction in the rate. Calcium chloride showed an increase in the reaction rate for both cases of the presence and the absence of a corrosion inhibitor.
The results also showed that mutual solvent changed the dissolution rate and a minimum was observed at 5 vol%. These results were confirmed by changing the corrosion inhibitor and the same behavior was observed at the same mutual solvent concentration. Dissolved iron reduced the rate of reaction by 17% at iron concentration up to 5000 mg/l. At 17,000 mg/l, the rate was reduced by 39% and a reddish to brown precipitate of ferric hydroxide was observed on the rock samples after the reaction, indicating a ferric precipitate. The reaction of VES-based acid showed a minimum at 125°F, which matched the maximum viscosity at low shear rate. The presence of 5 wt% chelating agents increased the reaction rate of 0.1 N HCl by 12.7 and 25%, when the reactions were conducted with no corrosion inhibitors and with 1 vol% CI-A, respectively.
Additives change the reaction of HCl with calcite, and these changes should be considered when the acids are used in matrix acidizing or acid fracturing.
This paper describes a detailed geochemical evaluation of the Paleozoic source rocks in the Chotts basin- Southern Tunisia. Cutting samples collected from Middle Ordovician Azzel Formation (Fm), Late Silurian-Early Devonian FegaguiraFm and Permian ZoumitFm were analysed using Rock-Eval pyrolysis, GC and GC/MS techniques.
The FegaguiraFm is the principal petroleum source rock (SR) in the basin with Total Organic Carbon (TOC) values ranging from 1 to 20%. The Petroleum Potential (PP) and the Hydrogen Index (HI) values average 8 kg HC/t rock and 225 mg/g of TOC respectively indicate that the sediments have oil and gas generating potential. The terpanes series are dominated by the tricyclic and tetracyclic terpanes comparatively to hopanes with C23, C24 and C21 tricyclic terpane as prominent compounds. The diasterane contents are relatively high confirming the shaly character of the SR.
The Azzel shales has poor to moderate, occasionally good, potential for sourcing oil and gas with TOC and PP values varying from 0.80 to 4.49 % and from 0.68 to 9.20 kg of HC/t rock respectively. The HI values of 95–165 mg S2/g TOC and Tmax value of 435–448°C indicate mainly mature oil-prone kerogen. The biomarker features are characterized by high proportion of tricyclic terpanes that are dominated by C23 and C21 tricyclic terpanes. The hopanes fraction is dominated by C29 and C30 hopanes. The diasterane content are relatively high supporting the shaly character of the SR.
The ZoumitFm shows fair to excellent TOC ranging from 0.06 to 6.84% and fair to good PP (reaching 4.77 kg of HC/t of rock) and both HI and Tmax values indicate mainly immature oil-prone kerogen. The biomarker analysis reveals a low content of trictyclic terpanes relative to pentacyclic terpanes. The content of C29 and C30 hopane is relatively high. The diasteranes are present in moderate to high proportions and are less abundant than regular steranes. These biomarker features indicate a marine OM associated with marly to argillaceous limestone SR, deposited in suboxic, normal salinity depositional environment.
Abdalla, Omar Shehata (PetroSilah Petroleum Company) | Shawky, Mohamed (PetroSilah Petroleum Company) | Badawy, Omar (PetroSilah Petroleum Company) | Maarouf, Mounier (PetroSilah Petroleum Company) | kamal, Youssuf (PetroSilah Petroleum Company)
Field development planning is one of the core business processes in the upstream oil and gas industry. Before a discovered field can be developed and its hydrocarbon produced, proper evaluation and planning of the subsurface reservoirs and surface facilities are necessary to ensure that the field development plan is not only economical to undertake, but also flexible enough to cater for any deviation from the original plan during implementation as a result of inherent uncertainties in the reservoirs over the production life span of the field. This paper describes the approach taken to prepare a Field Development Plan (FDP) for one of the old mature fields in the western desert of Egypt which operated by PetroSilah Petroleum Company in the concessions area in El-Fayoum, 90 Km south of Cairo. PetroSilah Petroleum Company operates more than 15 mature fields with very limited sand structure and depletion drive reservoirs mechanism, two common denominators among these fields is the high pour point of the produced oil and the lake of surface facilities for crude assembling and shipping since crude oil is transported by trucks. The driver for this FDP was the requirement to maximize and improve existing field's production, starting 3rd quarter of 2012 FFDP initiated when total daily production rate of PetroSilah was 3500 BOPD such as work-over/re-completions campaign, new infill development and exploratory/appraisal wells have been drilled in addition to hydraulic fracture campaign and water injection project which started in some fields and preparation for other existing have been applied, results showed an increase of total average daily production up to 7000 BOPD. The key areas emphasized in the preparation of the field development plan include the business driver, resource assessment, depletion strategy, development concept and selection, managing uncertainties, appraisal requirements, reservoir management, and anticipating production problems.
Salah, Mohamed (Khalda Petroleum Company) | Bereak, Ahmed (Khalda Petroleum Company) | Gabry, M. A. (Khalda Petroleum Company) | Gallab, M. (Khalda Petroleum Company) | Fattah, S. I. Abdel (Khalda Petroleum Company)
Abu Roash-D (AR-D) is a common carbonate reservoir in Abu Gharadig (AG) field, Western Desert of Egypt. It is characterized as a limestone reservoir which has good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. The heterogeneity and tightness of AR-D reservoir are the main challenges to maintain economical well productivity.
Initially, Several vertical wells had been drilled in AR-D reservoir and stimulated via matrix acidizing, but could not achieve or sustain the economical target production rates. Recently, two vertical wells were acid fractured as a trial to produce conductive fracture with sufficient length to allow more effective drainage around the wellbore, but test results showed higher flash production of 3,000 BOPD then rapid decline and low recovery occurred. This awesome results encourage embarking on field development and additional production data gathering for development optimization. The large interest in developing such low permeability reservoirs has been a direct result of the favorable economics achieved by the advancements in horizontal well drilling and stimulation technologies hold great promise to increase production by dramatically increasing the contact area with the producing interval, maximizing the drainage volume around a well and link those natural fractures network.
So, In order to economically develop AR-D reservoir resources a comprehensive parametric study was conducted on low permeability AR-D reservoir of western desert (through gathering of additional data during the development a major reservoir, the review of the core and test permeability data across the reservoir as well an evaluation of the uncertainties and associated development risks) has documented some critical results, showing the productivity index ratio between stimulated vertical and horizontal wells illustrates the improvement to be obtained from higher reservoir contact.
This paper takes a multidisciplinary approach to better understand how to enhance the productivity of low permeability AR-D reservoir in Western desert of Egypt through a detailed analysis of well performances and exploitation approaches after the successful Implementation of horizontal wells to maximize drainage volume around the well to revive low producing wells due to reservoir tightness and discuss the actual performance of the horizontal wells and compares them with the offset conventional vertical wells and highlights the productivity gain.
The recent achievement in unconventional reservoirs has established the objective of reevaluating the oil-bearing tight carbonates as potential oil production reservoirs. Of these carbonates, the Turonian Abu Roash D (AR/D) tight limestone in the Abu Sennan field of the Western Desert, Egypt contains oil, but has extremely poor recovery. The challenge in this study is to define the effective parameters that control the various petrophysical attributes of this tight reservoir and their influence on reservoir recovery.
Integrated sedimentological analysis and poroperm characterization was performed based on various data sets, including conventional core analysis, mercury injection tests, and petrographic inspection. A core-calibrated image-perm software algorithm was processed to evaluate the heterogeneity of reservoir pore system and to provide a continuous and azimuthal output of high resolution porosity and permeability.
The AR/D limestone succession (approximately 82 m thick) consists almost entirely of offshore-outer ramp bioclastic wackestone-mudstone facies, with the exception of a reduced reservoir-forming interval (approximately 10 m thick), which consists of inner- to mid-ramp facies. The outer-ramp offshore facies have very poor reservoir quality, with total porosity of less than 9% and permeability values that never exceed 0.1 mD. The reservoir-forming interval begins with storm beds of whole fossil rudstone and bioclastic wackestone, and gradationally terminates upward with inner-ramp shoal beds (5 m thick) of benthic foraminiferal peloidal packstone. The shoal facies measure a noticeably enhanced porosity (15 to 27%) with a relative increase in permeability (up to 2.3 mD). However, a petrographic inspection with resistivity image analysis showed a clear paucity of visible mega- and meso-pores or significant natural open fractures. This means that the reservoir pore system is of the intercrystalline microporosity type, which is confirmed by scanning electron microscope (SEM) and the measured pore throat radii ranging between 1 and 0.005µ. The prevalence of microporosity in the best zone of AR/D reservoir is also evident by a unimodal porosity range distribution shown by an image-perm output. This homogeneous and volumetrically significant microporosity nature may provide a favorable recovery if a suitable fracturing design is applied.
This study highlights the effect of microporosity types on the permeability of tight limestone reservoir, and emphasizes the workflow and benefits of the image-perm technique in evaluating the poroperm system and heterogeneity in the porosity distribution in carbonate reservoirs.
The development of pressure transient analysis was originally based on single phase flow for slightly compressible fluids. It was later extended to include dry gas flow and multiphase conditions.
In this work, we explore the accuracy of the three most commonly used multiphase pressure transient analysis methods [single phase analysis using composite model, Perrine Martin (P-M), and multiphase pseudo-pressure method] under various conditions. Our approach included using appropriate numerical simulation techniques to generate drawdown and buildup data for gas-oil system at variety of conditions of GOR, CGR. Then, each test was evaluated with the 3 well test analysis methods, and error between calculated and actual results was computed for each method. In each case, we compared the well test derived properties (e.g. permeability, skin, completion information) with actual properties (given from numerical reservoir simulation). We tested various oil and gas properties spanning different fluid types of gas condensates and volatile oils. The testing also included different common well testing models such as radial, limited entry, hydraulically fractured, and horizontal wells. We then embarked on detailed analysis of these errors to derive conclusions regarding which methods give more accurate results under which conditions.
As an example, application of the three analysis approaches to horizontal well models in gas condensate reservoirs using different actual fluid samples with varying composition, at different levels of drawdown; it was found that (1) single-phase with composite reservoir method underestimated the permeability by 8% for very lean gas-condensate and by 18% for rich gas condensate fluid sample, (2) Perrine Martin method was able to predict the permeability with error <17% at low gas production rate, and (3) multiphase pseudo-pressure functions (steady state and three-zone) produced best results with permeability error less than 4% for lean gas-condensate samples, and by 16% for very rich gas condensates. Many other useful conclusions for different systems were also derived. These conclusions show the expected level of error for properties predicted from well test analysis under different conditions of multiphase and for different well test models. Using these conclusions, a list of guidelines was recommended for well test analysis in multiphase tests.
El Gogary, Ahmed. F. (Belayim Petroleum Company (Petrobel)) | El-Masry, Hossam. H. (Belayim Petroleum Company (Petrobel)) | Kortam, Mostafa. M. (Petrobel) | El-Rayek, Hany. R. (Belayim Petroleum Company (Petrobel))
Horizontal and highly deviated wells are increasingly being used in oilfield developments worldwide. Large-bore horizontal wells can deliver significantly higher oil production rates than conventional completions, reducing field development costs by allowing reserves to be targeted with fewer wells
Rudies formation in Belayim Land field is a bottom water-drive reservoir with a strong supporting aquifer. it is characterized by its great isotropy and heterogeneity where based on the analysis of SCAL data, it was found that the vertical permeability is nearly equal to horizontal permeability raising the problem of water coning(cresting), earlier water breakthrough situation and masking the oil production by water due to the great difference in mobility
Based on calculation of the critical coning production rates and water control plots it was concluded that the horizontal wells drilled in Rudies formation which are produced with high production rates suffered from extreme water coning problems that raised the necessity for water shutoff procedure to be considered
Field cases presented on this paper explain applications of internal casing packer and blank tubing as a tail pipe in accompanied with downgrading the production rates from horizontal wells for the purpose of zonal water control in the uppermost section of open hole and slotted liner completed horizontal wells in Petrobel
Included in this paper are two different field cases for uncemented water shutoff in horizontal wells that succeeded in decreasing the water cut in the wells from the range of (90-95 %) to the range of (10-30%) implementing a huge increase in the gained net oil towards achieving the maximum recovery. Technical data including well configuration, production performance and casing string are included in the paper. Field operations and lesson learned from each application are also presentedinthispaper
Mendez, Freddy E. (Baker Hughes Incorporated) | Siddiqui, Aamir (Baker Hughes Incorporated) | Hanif, Amer (Baker Hughes Incorporated) | Longo, John (Baker Hughes Incorporated) | McGlynn, Ian (Baker Hughes Incorporated) | Gade, Sandeep (Baker Hughes Incorporated) | Blood, David R. (EQT)
Spectral analysis of natural and stimulated gamma rays is a well-established open-hole technology that enables accurate mineral characterization and petrophysical evaluation of conventional and unconventional reservoirs. The determination of detailed mineralogy in the cased-hole environment, however, has been a challenge because of the significantly increased uncertainties caused by the additional attenuation and contribution effects of casing and cement that are observed in the gamma ray spectra. The acquired spectral gamma ray data is processed with proprietary algorithms that are based on a combination of lab experiments and modeled tool response standards. The resulting elemental composition, corrected for the cased-hole environment, is further processed in an expert interpretation system to determine lithology and detailed mineralogy of the target formation. Candidates for this technology include older and newly cased wells where lithology and detailed mineralogy from open-hole logs are not available.
This work discusses some aspects of the corrections needed for an accurate quantification of chemical elements from measurements through casing. The impact of casing collars and presence of cement on the spectral data are also discussed. Finally, we report a case study that uses this technology and illustrates a successful mineral characterization of a complex reservoir rock in the United States. Results show good agreement with an x-ray difraction (XRD) analysis of ditch cuttings. The resulting logs were productively used by the operator to understand the siliciclastic influx as well as the distribution of carbonates in the Big Lime formation. The results also show the ability of the methodology to identify organic carbon directly from measurements of the inelastic spectrum in the cased-hole environment.
The application of pulsed neutron technology (PNT) in cased holes has, so far, been limited to basic lithology identification. This methodology expands the applicability of the PNT, previously mostly confined to open-hole cases, to the cased-hole environment and enables operators to take full advantage of the valuable information contained in high-resolution inelastic, capture and natural spectra. This enables characterization of hydrocarbon-bearing formations to a level of detail previously possible only from open-hole data.
Low-density water-based drilling fluids formulated with hollow glass spheres (HGS) offer an attractive drilling method. HGS are incompressible lightweight additives with the capability to reduce mud weight down to 41.0 lbm/ft3 (5.5 lbm/gal). Several pressure ratings of HGS are available, and selecting the appropriate rating is essential to avoid formation damage and lost circulation in near-balance conditions. Failure of the spheres could thus lead to catastrophic results.
The objectives of this paper is to evaluate the stability of inhibited water-based drilling fluids formulated with HGS in diverse pH environments, and assess their potential application in Wasia formations in Saudi Arabia. Wasia formation is composed of middle cretaceous clastic rocks with layers of sandstone, shale and occasional limestone. Wasia is an aquifer with a thick unit that crops out in central Najd with a slight eastward dip (
We conducted comprehensive analysis of HGS performance in various pH environments to assess their stability in drilling fluids. Mud characteristics and rheological properties were examined before hot rolling (BHR) and after hot rolling (AHR) to determine the effects of high pressure and high temperature (HPHT) on the system. The duration at which the samples were exposed to HPHT conditions varied from 1 to 4 days to understand the behavior of the mud over time. In addition, two typical formulations were prepared using HGS and conventional additives to evaluate their properties and compare them to the American Petroleum Institute (API) standards.
Hollow glass microspheres were found to be stable in the pH conditions of drilling operations (pH ~9), with a maximum density variation of 0.5 lbm/ft3. At higher pH levels (pH >11), the spheres experienced fractional dissolution due to the reaction of the added NaOH with borosilicate glass. In pH ranges lower than 4, the spheres were found to be extremely stable. The inhibited water-based fluids formulated with HGS produced favorable rheology and stable mud characteristics before and after exposure to the actual downhole temperatures of Wasia formation.
Traditionally, several multiphase hydraulic calculations are required to determine the permissible surface-parameter operating envelope in underbalanced drilling (UBD) operations to estimate how bottomhole pressure (BHP) and the desired underbalanced condition can be achieved. Furthermore, the complexity consists of running several combinations of gas- and liquid-injection rates and overlapping these results with operating constraints, including the operating range of equivalent liquid rates for downhole mud motors, minimum annular velocities for effective hole cleaning, desired BHP, and respective surface-equipment limitations, to visualize a comprehensive spectrum of viable surface parameters. This paper explains and illustrates a novel method for obtaining quick and comprehensive operational envelopes for underbalanced drilling operations.
The model used for pressure-drop calculations considers the effect of geothermal and string temperatures, detailed drillstring and wellbore geometries (including tool joints), formation fluid influxes at several depth intervals, cutting-slip effects, and surface back pressure. This model also enables the evaluation of the behavior of multiphase drilling fluid using different gas correlations.
The system determines bottomhole pressures for several combinations of injection parameters and automatically collects results to generate a permissible operating area (envelope).
Measured times to generate the operating envelope graph and a comparison of the results are evaluated for several methods and wellbore hydraulic simulators; a qualitative evaluation and validation against field data is also included. The method outlined in this paper offers an alternative to automatically obtaining a gas- and liquid-injection operating envelope, which results in a time savings of three orders of magnitude, as compared to traditional procedures and computational solutions.
One of the limitations of the model is that the operating envelope is for a single wellbore depth and provides a representation of the pressure achieved at a fixed depth. Recommended developments will consist of the ability to visualize BHP values for drilling depths, perhaps through a 3D graph.
This paper describes the method used by a multiphase flow simulator to create a graph that aids in determining and visualizing the operational area to achieve a specific BHP, including the hydrostatic and friction-dominant areas of circulation; this development will facilitate the decision-making process while designing the wellbore hydraulic aspects of an underbalanced drilling operation. The benefits of the multiphase flow simulator include a significant time savings to obtain a visual representation of bottomhole conditions and the ability to quickly achieve optimized results by means of a broader sensitivity analysis.